&EPA
Air Pollution Training Institute
MD20
Environmental Research Center
Research Triangle Park, NC 27711
EPA 450/2-83-001
January, 1983
Air
APTI
Course 474
Continuous Emission
Monitoring
Regulatory Documents
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United States
Environmental Protection
Agency
Air Pollution Training Institute
MD20
Environmental Research Center
Research Triangle Park, NC 27711
EPA 450; 2-83-001
January, 1983
Air
APTI
Course 474
Continuous Emission
Monitoring
Regulatory Documents
Edited by:
James A. Jahnke, Ph.D.
Northrop Services, Inc.
P.O. Box 12313
Research Triangle Park, NC 27709
Under EPA Contract No.
68-02-2374
EPA Project Officer
R. E. Townsend
United States Environmental Protection Agency
Office of Air, Noise and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
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Notice
This is not an official policy and standards document. The opinions and selections
are those of the authors and not necessarily those of the Environmental Protection
Agencv. Every attempt has been made to represent the present state of the art as
well as subject areas still under evaluation. Any mention of products or organizations
does not constitute endorsement by the United States Environmental Protection
Agency.
Availability
This document is issued by the Manpower and Technical Information Branch, Con-
trol Programs Development Division, Office of Air Quality Planning and Standards,
USEPA. It was developed for use in training courses presented by the EPA Air Pollu-
tion Training Institute and others receiving contractual or grant SUPPOTt from the
Institute. Other organizations are welcome to use the document.
If these materials are adapted or abstracted, it is requested that professional
courtesy be shown through proper citations to this document.
This publication is available, free of charge, to schools or governmental air pollu-
tion control agencies intending to conduct a training course on the subject covered.
Submit a written request to the Air Pollution Training Institute, USEPA, MD 20,
Research Triangle Park, NC 27711.
Others may obtain copies. for a fee, from the National Technical Information
Service (NTIS), 5825 Port Royal Road, Springfield, VA 22161.
11
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Preface
This document is a compendium of regulatory announcements and promulgations
dealing with continuous source-emission monitoring. We have attempted to include
most of the pertinent Federal Register announcements (from October 6. 1975 to
December I, 1982) dealing with this subject. A number of the Proposed Rules and
A dvanced Notices of Proposed Rulemaking that are included here have not as yet
been, or will not be, promulgated as final rules. They are incorporated here because
they indicate trends in agency policy and, in many cases, provide technical
approaches that would be difficult to find without specific knowledge of Federal
Register publication dates.
Starting from the October 6. 1975 Federal Register announcement of continuous-
monitoring regulations. all entries follow chronologically in this publication.
1U
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Table of Contents
Regulations for the Continuous Monitoring of Source Emissions.
Section I -- Selected Information on New Source Performance Standards.
A. Federal Standards of Performance for New Stationary
Sources of Air Pollution
B. Summary of Proposal and Promulgation Dates
for NSPS Source Categories
C. Selections from the Code of Federal Regulations. .. .
1. Sections 40 CFR 60.5 to 40 CFR 60.14.
2. Subpart G - Standards of Performance for Nitric Acid Plants.
3. Subpart H - Standards of Performance for Sulfuric Acid Plants
4. Subpart P-Standards of Performance for Primary Copper
Smelters. . . .
5. Subpart Q-Standards of Performance for Primary Zinc
Smelters. . . . . . . . . . .. .. . . . . . . . . . .
6. Subpart R-Standards of Performance for Primary Lead
Smelters. . . . . .. . '" .....
7. Method 20 - Determination of Nitrogen Oxides, Sulfur
Dioxide, and Oxygen Emissions from Stationary Gas
Turbines. . .. ....... . . . . .. .
Section II - Selected Excerpts from the Federal Register. ...
1. October 6, 1975-40 FR 46240 Requirements for
Submittal of Implementation Plans- Standards for New
Stationary Sources - Emission Monitoring
2. October 12, 1976-41 FR 44838 Emission Monitoring
Requirements- Receipt of Application and Approval
of Alternative Monitoring Requirements.. ..
3. January 31,1977-42 FR 5936 Revisions to Emission
Monitoring Requirements and to Reference Methods
4. May 23, 1977 -42 FR 26205 Compliance with Standards
and Maintenance Requirements
5. December 5. 1977 -42 FR 61537 Opacity Provisions for
Fossil-Fuel-Fired Steam Generators- Revision of Format
and Reporting Requirements. . .
6. May 31, 1979 - 44 FR 31514 Polychlorinated Biphenyls
(PCBs) Manufacturing, Processing, Distribution in
Commerce, and Use Prohibitions (Selected
Sections - Monitoring Disposal by Incineration) .
7. June 11, 1979 - 44 FR 33580 New Stationary Source
Performance Standards; Electric Utility Steam Generating
Units (Subpart Da Promulgation). .
v
Page
I
L,
17
26
27
27
3~
33
34
. 36
37
39
47
49
83
87
90
~) I
93
101
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8. June 29. 1979-44 FR 37960 Adjustment of Opacity Standard
for Fossil-Fuel-Fired Steam Generator (Southwestern Public
Service Co. - Harrington Station, Proposed Rule) ........ .. 147
9. August 8. 1979-44 FR 46481 Emission Monitoring of
Stationary Sources - Advanced Notice of Proposed
Rulemaking. . . . . . . . . . .. .... . . . . . .. .. """ . 148
10. September 20, 1979-44 FR 54507 Proposed Approval of an
Administrative Order Issued by the South Carolina
Department of Health and Environmental Control to the U.S.
Department of Energy. Savannah River Operations Office.. .149
11. September 27,1979-44 FR 55651 Montana Power Co..
Colstrip Units No.3 and No.4; Approval of PSD Permit. . . . 151
12. October 10. 1979-44 FR 58602 Continuous Monitoring
Performance Specifications (Proposed Revisions..
Specification Tests I, 2. and 3). . . . . . .. ................. 153
13. October 22, 1979-44 FR 60760 Standards of Performance
for New Stationary Sources: Petroleum Refineries;
Review of Standards. . . . . . . . . . . . ... . . . . . . . . . . . . . . . . . . 189
14. October 22, 1979-44 FR 60761 Standards of Performance
for New Stationary Sources: Portland Cement Plants;
Review of Standards. . . . . . . . . . . . . . . . . . . . . .. ...... ... . 190
15. December 4, 1979-44 FR 69683 Approval and Promulgation
of Implementation Plans; Florida: Variance for Particulates,
S02, Visible Emissions and Excess Emissions for Florida Power
and Light Generating Plants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192
16. December 28, 1979-44 FR 76786 Adjustment of the Opacity
Standard for a Fossil-Fuel-Fired Steam Generator (South-
western Public Service Co. - Harrington Station, Final Rule) . . . 193
17. February 4,1980-45 FR 7762 Standards of Performance
for New Stationary Sources; Ammonium Sulfate
Manufacture - Selection of Monitoring Requirements.. ..... 194
18. February 6, 1980-45 FR 8230 Standards of Performance for
New Stationary Sources for Electric Utility Steam Generating
Units; Decision in Response to Petitions for Reconsideration
(Excerpts) . .. .................. .. .........195
19. February 14, 1980-45 FR 9994 Regulation of Large Coal-
Fired Boilers for S02 Emissions (Statistical Model) . . . . . . . . . .200
20. February 20, 1980-45 FR 11444 Continuous Monitoring
Performance Specifications- Advanced Notice of Proposed
Rulemaking (Performance Specification Test 4, CO
Monitoring Systems). ... . . . . . . . . . .
21. June 4, 1980-45 FR 37729 Amended Permit Determination
to Indianapolis Power and Light, Patriot, Ind. .
22. June 13. 1980-45 FR 40169 Approval and Promulgation of
Implementation Plans; Utah S02 Control Strategy (Kennecott
Copper Corp.).
VI
.203
.207
~lO
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23. June 19, 1980-45 FR 41415 Energy Related Authority;
Delayed Compliance Order for the Virginia Electric and
Power Company's Portsmouth Generating Station.. .
24. November 12, 1980-45 FR 74737 Georgia Plan Revision
Relating to Georgia Power Plant Harlee Branch; Approval
and Promulgation of Implementation Plans.
25. January 8, 1981-46 FR 2186 Collection of S02 Emissions
Data from Certain Coal-Fired Utility Steam Generating Units. .218
26. January 26, 1981-46 FR 8352 Revisions to General Provisions
and Additions to Appendix A, and Reproposal of Revisions
to Appendix B .. ...... ...
27. July 20, 1981-46 FR 37287 Continuous Monitoring Perfor-
mance Specifications; Proposed Revisions to General Provisions
(Advanced Notice of Proposed Rulemaking- Performance
Specification Test 5 - Total Reduced Sulfur- TRS) .
28. October 28, 1981-46 FR 53144 Alternate Method 1 to
Reference Method 9 of Appendix A - Determination of the
Opacity of Emissions from Stationary Sources Remotely by
Lidar; Addition of Alternate Method . . ~39
29. December 1, 1982-47 FR 54073 Methods 6A and 6B for the
Determination of S02. Moisture, and CO2 Emissions from
Fossil Fuel Combustion Sources. . . . .257
.2H
.217
.223
.236
Vll
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Regulations for the Continuous
Monitoring of Source Emissions
Introduction
The Federal Register and Code of Federal Regulations
Basically, there are two publications of which agency or industrial personnel involved
with monitoring systems should be aware: the Federal Register (FR) and the Code of
Federal Regulations (CFR). An issue of the Federal Register is published every
working day. It presents proposed and promulgated regulations, amendments to pre-
viously promulgated regulations, meeting announcements, and other announcements
for all agencies of the Federal government. The Code of Federal Regulations,
published only once a year, is essentially a compilation of all of the promulgated
regulations and amendments published that year in the Federal Register by the
executive departments and the agencies of the Federal government. If an amend-
ment to a paragraph of a promulgated regulation was published in the FR, the new
CFR would strike out the old paragraph of the regulation and put in the amended
version. The CFR is kept up to date by the individual issues of the Federal Register.
The two publications must be used together to determine the latest version of any
given rule.
The CFR is divided into 50 titles, each concerning some area of interest. For
example, Title 14 deals with Aeronautics and Space and covers announcements and
rules made by the Federal Aviation Administration, the Civil Aeronautics Board,
and NASA. The title that concerns us is Title 40, which covers the Environmental
Protection Agency, the Low-Emission Vehicle Certification Board, and the Council
on Environmental Quality. We will deal with those regulations proposed and
promulgated by EPA, which come under Chapter I of Title 40.
Chapter I of Title 40 is divided in the following manner:
Title 40 - Protection of the Environment
Chapter 1- EPA
Subchapters (A-Q)
Parts (0-799)
Subparts (A- TT)
Sections (Part No. + Decimal)
Appendices (A-Z)
It can be seen from this division that the Subchapters extend from A through Q
and the Parts, from 0 through 799. The numbering of the "Parts" extends through
the Subchapters (i.e., Subchapter B ends with Part 49 and Subchapter C begins with
Part 50). Many of the Subchapters and Parts have been "reserved"; they have not yet
been assigned to a specific regulatory area. This is meant to provide room for expan-
sion within the format of the existing CFR.
1
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In the CFR organizational scheme, Subchapter C deals with Air Programs, the
main area of interest here. Subchapter C includes Pans 50 through 89, as shown
below,
Titl«: 40 Subchapter C-Air Programs
Part
50
National primary and secondary ambient air quality
standards
Requirements for preparation, adoption. and submittal
of implementation plans
Approval and promulgation of implementation plans
Ambient air monitoring references and equivalent
methods
Prior notice of citizen suits
Energy-related authority
Standards of performance for new stationary sources
National emission standards for hazardous air pollutantS
Registration of fuels and fuel additives
'Regulation of fuels and fuel additives
Air quality control regions. criteria. and control
techniques
Control of air pollution from new motor vehicles and
new motor vehicle engines
Control of air pollution from new motor vehicles and
new motor vehicle engines: certification and test
procedures
Control of air pollution from aircraft and aircraft
engines
(Reserved)
51
52
53
54
55
60
61
79
80
81
85
86
87
88-89
2
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The Parts, which are numbered, are further divided into Subparts, as is shown
below. In Part 60 (of Title 40), which applies to the New Source Perfonnance
Standards, the Subparts currently are labeled from A through Z and from AA
through TT. Each Subpart after Subpart C refers to the regulations that apply to a
specific industry. For example, Subpart G applies to Portland Cement Plants, and
Subpart H applies to sulfuric acid plants.
Title 40 Part 60 eFR Subparts'"
Subpart A - General Provisions
Subpart B - Adoption and Submittal of
State Plans for Designated Facilities
Subpart C - Emission Guidelines and
Compliance Times
Subpart D-Fossil-fuel fired Steam
Generators
Subpart Da - EleCtric Utility Steam
Generating Units
Subpart E- Incinerators
Subpart F - Portland Cement Plants
Subpart G - Nitric Acid Plants
Subpart H - Sulfuric Acid Plants
Subpart 1- Asphalt Concrete Plants
Subpart J - Petroleum Refineries
Subpart K-Storage Vessels for Petroleum
Liquids
Subpart L - Secondary Lead Smelters
Subpart M - Secondary Brass and Bronze
Ingot Production Plants
Subpart N - Iron and Steel Plants
Subpart 0 - Sewage Treatment Plants
Subpart P- Primary Copper Smelters
Subpart Q - Primary Zinc Smelters
Subpart R - Primary Lead Smelters
Subpart S - Primary Aluminum Reduction
Plants
Subpart T Phosphate Fertilizer Industry:
Wet Process Phosphoric Acid Plants
*l1pdated to January I. 19R3.
Subpart U - Phosphate Fertilizer Industry:
Superphosphoric Acid Plants
Subpart V - Phosphate Fertilizer Industry:
Diammonium Phosphate Plants
Subpart W - Phosphate Fertilizer Industry:
Triple Superphosphate Plants
Subpart X - Phosphate Fertilizer Industry:
Granular Triple Superphosphate Storage
Facilities
Subpart Y - Coal Preparation Plants
Subpart Z-Ferroalloy Production
Facilities
Subpart AA - Steel Plants: EleCtric Arc
Furnaces
Subpart BB -- Kraft Pulp Mills
Subpart CC.- Glass Manufacturing Planb
Subpart DD - Grain Elevators
Subpart EE - Surface Coating of Metal
Furniture
Subpart GG-Gas Turbines
Subpart HH - Lime Manufacturing Plants
Subpart MM - Automobile and Light Duty
Truck Surface Coating Operations
Subpart PP - Ammonium Sulfate
Manufacturing
Subpart SS - Industrial Surface Coating:
Large Appliances
Subpart TT - Metal Coil Surface Coating
3
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Each Section number begins with the Part number under which it falls. Decimal
notation is then used to complete the number. For example. under Subpart A-
Cp\wral Provisions -- the discussion of "Monitoring Requirements" for new stationary
sou rees comes under Section 60.13.
Sections of the Subparts of Part 60*
Chapter I-Environmental Plotection Agency
PART 60-STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Subpart A-General Pravisians
SH'.
60.l AppJlC'ablllly.
602 Ddil1ltions.
GIU VI)!!' and abbreviations.
60.4 Addn'ss.
605 Dl'll'rmination of conslru~tion
IIwdification.
60.6 R('\'j,'w of pla~s.
61).7 Notification and record kpeping.
60.8 Performance lpsts.
GO 9 A';ailability of mformation.
60.10 Slat.. allt:10rily.
60.11 Compliancp with standards
maintenanc(' rt'Qulrempnts.
61112 Clrcum\'('ntion
GO.13 MOl1ltnring f'('quirpmpnl'.
60.14 Modi fi"at Ion.
6U 15 Ro'('onstrllct Ion.
6016 Priority list.
Subpart 8-Adoption and Submittal of State
Plans for Designated facilities
60.20 Applicability
60.21 Dt'fmitions.
60 22 Publication of guidelmp documents.
emlS,ion guidelines. and final compli-
anct' tunes.
6023 AdoptIOn and submittal ')f State
plans: public hearIngs.
60.24 Emission standards and compliance
schpdulps.
60.25 Emission im'pntories. source survpd.
lancp. reports.
60.26 Lt>gal authority.
60.27 Actions by the Administrator.
60 28 Plan r('VISlons by the Statt'.
60.29 Plan 1'1'\ iSlOns by the Admimstrator.
Subpart C-Eminion Guidelines and
Compliance Times
60 :JO
6031
60.32
60.33
6034
Seop...
Definitions.
DesIgnated facilities.
Emi"sion guidl'lines.
Compliance times.
Subpart D-Standards 0' Performance for
fonil-Fuel fired Steam Generators for Which
Construction is Commenced After August 17,
1971
60.40 Applicability and designation of af.
ft'ctcd faCIlity
Part 60
Spc.
60.41
60.42
60.43
60.44
60.45
60.46
Definitions.
Standard for particulate matter.
Standard for sulfur dioxide.
Standard for nitrogen oxides.
Emission and fuel monitoring.
Test mt'thods and procedures.
or
Subpart Da-Standards of Performance for
Electric Utility Stllam Generating Units for
Which Construction Is Commenced After Sep-
tember 18,1978
60.40a Appllcabilily and designation of af.
[('cled facility.
60.41a Dpfinitions.
60.42a Standard for particulatt' matter.
60.43a Standard for sulfur dioxide.
60.44a Standard for nitrogpn ox!des.
60.45a Commercial demunstration permit.
60.46a Compliancp provisions.
60.47:\ Emission monitoring.
60.48:\ Cornpliann' d.'t.'rminat Ion pro!'o-.
durl's and m('thods.
60.49:\ Reporting requin'mt'Ill~.
and
Subpart E-Standards of Performance for
Incineratars
60.50 Applicability and designation of af.
feded facility.
60.51 Definitions.
60.52 Standard for part kulate matt"r.
60.53 Monitoring of opt'rations.
60.54 Test m('thods and procpdurps.
Subpart f-Standards of Performance for
Portland Cement Plants
60.60 Applieability and designation of af-
fp('led facility.
60.61 Definitions.
60.G2 Standard for particulate matter.
60.63 Monitoring of operations.
60.64 Tf'st mt'thods and proct'durps.
Subpart G-Standards of Performance for
Nitric Acid Plants
60.70 Applicability and designation
fpcled facihty.
60.71 Definitions.
60.72 Standard for nitrogpn oxides.
60.73 Emission monitming.
60 H Test methods and proc('dures.
of af.
Subpart H-Stondardl of Performance for
Sulfuric Acid Plants
60.80 Applicabilo t y and d('signation
f('cted facility.
60.81 Definitions.
60.82 Standard for sulfur dioxidf'.
of af.
'Taken from Code of Federal Regulations Title 40 Parts 53 to 80. Revispd as of July I, 1981.
4
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Part 60
Sec.
60.83
60.84
60.85
Standard for acid mist.
EmissIOn monitoring.
Tl'sl n1l'l hods and procl'durt.s.
Subpart I-Standards af Perfarmance for
Asphalt Cancrete Plants
60.90 Applicability and dl'signation of af.
fl'ctl'd facility.
60.91 Definitions.
60.92 Standard for particulatl' matll'r.
60.93 Test methods and procl'durl's.
Subpart J-Standards of Perfarmance for
Petraleum Refineries
60.100 ApplICability and d"Slgnation of af.
fl'ctl'd fal'llity.
60 101 Dl'finitions.
60.102 Standard for particulatl' maller.
60.103 Standard for carbon monoxide.
60.104 Standard for sulfur dioxide.
60.105 Emission monitoring.
60.106 Test mpthods and procedures.
Subpart K-Standards of Performance for Stor-
age Vellels for Petroleum liquids Construct-
ed after June 11, 1973 and Priar to May 19,
1978
60.110 Applicability and dl'signalion of af.
fl'ctl'd facility.
60.111 Dl'fi!1ltions.
60.112 Standard for volatile on:anic com.
pounds
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Chapter I-Environmental Protection Agency
Subpart S-Standards of Performance for
Primary Aluminum Reduction Plants
Spc.
60 190 Applicability and designation of af.
fpctl'd facility.
60.191 Dpfinitions.
60.192 Standard [or fluorides.
60193 Standard for visiblp emissions.
60.194 Monitoring of operations.
60.195 Test mpthods and procedurps.
'or the
Prace..
Subpart' -Standards of Performance
Phosphate Fertilizer Industry: Wet
Phosphoric Acid Plantl
60.200 Applicability and dpsignation of af.
fectpd facility.
60.201 Definitions.
60.202 Standard for fluorides.
60.203 MOnitoring of operations.
60.204 Test mpthods and procpdures.
Subpart U-Standards of Performance for the
Phosphate Fertilizer Industry: Superphos-
phoric Acid Plantl
60.210 Applicability and designation of af.
fected [acillty
60.211 Defmitions.
60.212 Standard for fl~orides.
60.213 Monitoring of operations.
60.214 Test methods and procpdurps.
Subpart V-Standards of Performance for the
Phosphate Fertilizer Industry: Oiammonium
Phosphate Plantl
60.220 Applicability and dpslgnation of af.
fpcted facility.
60.221 Ddinitions.
60 222 Standard for fluorides.
60.223 Monitoring of operations.
60.224 Test methods and procedures.
Subpart W-Standards of Performance for the
Phosphate Fertilizer Industry: Triple Super-
phosphate Plantl
60.230 Applicability and d~signation of af.
fectpd facility.
60.231 Df'finitions.
60.232 Standard for fluorides.
60.233 Monitonng of operations.
60.234 Test mpthods and procedurps.
Subpart X-Standards of Performance for the
Phosphate Fertilizer Industry: Granular Triple
Superphoophate Storage Facilities
60.240 Applicability and dpslgnation of a[.
fectt'd [adlity
60.241 Definitions.
60.242 Standard [or fluondps.
60 243 Monitoring of opprations.
602H Tl'st mpthods and procpdures.
Part 60
Subpart Y -Standards a' Performance for Coal
Preparation Plantl
Spc.
60.250 Applicability and designation of af.
fpcted facility.
60.251 Definitions.
60.252 Standards for particulate matter.
60 253 Monitoring of opprations.
60.254 Tpst methods and procedures.
Subpart Z-Standards of Performance for
Ferroallay Production Facilities
60.260 Applicability and dl'signation of af.
[ected facility.
60.261 Definitions. \
60.262 Standard for particulate matter.
60.263 Standard for carbon monoxide.
60.264 Emission monitoring.
60.265 Monitoring of operations.
60.266 Test methods and procpdures.
Subpart AA-Standards of Performance for
Steel Plantl: Electric Arc Furnaces
60.270 Applicability and designation of af.
fected facility.
60.271 Definitions.
60.272 Standard for particulatp mattpr.
60.273 Emission monitoring.
60.274 Monitoring of operations.
60.275 Tpst mpthods and procedurl's.
Subpart 88-Standards of Performance for
Kraft Pulp Millo
60.280 Applicability and designation or af.
fpctt'd facility.
60.281 Dpfinitions.
60.282 Standard for particulate matter.
60.283 Standard for total rpduced sulfur
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Part 60
Subpar" EE-FF-[Re.erved]
Subpart GG-Standards of Performance far
Stationary Gas Turbine.
Sec.
60.330 Appl1cability and designation
fected facility.
60.331 Definitions.
60.332 Standard for nitrogen oxidl's.
60.333 Standard for sulfur dioxide.
60.334 Monitoring of operations.
60.335 Tpst mpthods and procedures.
Subpart HH-Standards of Performance for
Lime Manufacturing Plan"
of af-
60.340 Applicability and designation of af-
fected facility.
60.341 Dl'fimtions.
60.342 Standard for particulate matter.
60.343 Monitoring of emissions and oper-
ations.
60.344 Tl'st methods and procedures.
Subpart MM-Standards 0' Performance for Auto-
mobile and Light-Duty Trude Surface Coating Oper-
ations
60.390 Applicability and designation of af-
fected facility.
60.391 Definitions.
60.392 Standards for volatile organic com-
pounds.
60.393 Performance tpst and compliancl'
provisions
60.394 Monitoring of I'mlssions and opl'r-
at Ions.
60.395 H,l'port ing and r"cordkl'pping re-
quirements.
60.396 Referencp n1('thods and procedures.
60.397 Modifications.
Subpart PP-Standards of Performance for
Ammonium Sulfate Manufacture
60.420 Appli('ability and designat ion of af.
fp('lt'd facility.
60.421 Dl'fll1ltlons.
60,422 Standard~ for particulate matter
60.423 Monitoring of operations.
60,424 Test methods and procedurps.
ApPENDIX A-REFERENCE METHODS
Mt'thod l~Samplt' and velocity tra\'l'rsc~
for stationary SOlllTPS.
Method 2-Dptprmination of staek gas \'p-
locity and volumetric flow rate (Typt' S
pi tot tubl' I.
Method 3-Gas analysis for carbon dioxidp,
oxygen, I'XCf'SS air, and dry molecular
wl'ight.
Method 4-Detl'rmination of moisturl' con-
tent in stack gases.
Method 5-Determination of particulate
emissions from stationary sourcf's.
Ml'thod 6-Determination of sulfur dioxide
emissions from stationary sources.
Title 40-Protection of Environment
Method 7-Determination of nitrogen oxidl'
emissions from stationary sources.
Method 8-Determination of sulfuric aCid
mist and sulfur dioxide emissions from
stationary sources.
Method 9- Visual df'tl'rmination of thl'
opacity of emissions from stationary
sources.
Method 10-DeterminatlOn of carbon mon-
oxide emissions from stationary sourcc.s.
Method ll-Determination of hydrogen sui.
fide content of fuel gas streams in petro-
leum refineries.
Ml'thod 12-IResen't'dJ
Mt'thod 13A-Determination of total flu.
orid" emissions from stationary
sources-SPADNS Zirconium Lake
Method.
Method 13B-DeterminatlOn of total flu-
oride emissions from stationary
sources-Specific Ion Electrode Method.
Method 14-Determination of fluoride emis-
sions from pot room roof monitors of pri-
mary aluminum plants.
Method 15-Dett'rmination of hydrogen sui-
fidl'. carbonyl sulfide. and carbon disul-
fide emissions from stationary sources.
Ml'thod 16-Semicontinuous determination
of sulfur emissions from st ationary
sources.
Method 17 -Determination of particulatl'
emissions from stationary sou reI's (in-
stack filtration method),
Method 18-IReser\'edJ
Method 19-Dl'termination of sulfur dioxide
rl'moval efficiency and particulate.
sulfur dioxidl' and nitrogt'n oxides t'mis-
sion rates from I'lectric utility stt'am
gent'rators.
Ml'thod 20-Determination of nitrogen
oxides, sulfur dioxide. and oxygt'n emis-
sions from stationary gas turbinf's.
Method 24-DeterminatlOn of Volatile
Matter Content, Water Content, Densi.
ty. Volume Solids. and Wc~ight Solids of
Surface Coatin~s.
Met hod 25-Determination of Tolal Gas-
!'ou~ Nonmpthane Orl(anic Emi:,sions a.s
Carbon.
ApPENDIX B-PERFORMANCE SPECIFICATIONS
Performance Specification I-Perform-
anCl' specifications and specification test
pro('edures for transmissomt'ter systpms for
cont inuous mt'asurem..nt of the opacity of
stack ..missions.
Performanct' Specification 2-Perform-
anct' specifications and specification test
procedures for monitors of SO, and NO.
from stationary sources.
Pprformance Specification 3~ Perform-
ance specifications and specification t!'st
procedures for monitors of CO, and 0, from
stationary sources.
ApPENDIX C-DETERMINATION OF EMISSION
RATE CHANGE
7
-------
It is often necessary to refer to rules published in the FR and CFR. Each publica-
tion has its own reference system. When referring to the FR, the date of publication,
the volume number. and the page number are sufficient to find a given regulation.
For example. the regulations dealing with the continuous monitoring of emissions
from new fossil-fuel-fired steam generators were promulgated in the Monday,
October 6. 1975 Federal Register. This would be written as follows:
40 FR 46250 (Octo,?er 6, 1975)
/ \ "'" ~
Volume no. Federal Page no. Date appearing
Register in FR
Referring to the promulgation in the CFR, however, is done by merely giving the
title number and the section number. The reference used to specify the regulations
in the CFR concerning the monitoring of new fossil-fuel-fired steam generators
would be as follows:
40 CFR 60.45
/ \ ~
Title no. Code of
Federal
Regulations
Section no.
These referencing methods are useful for locating specific passages in the
regulatory documents and for cross-referencing between documents.
The October 6, 1975 Federal Register
The Federal Register published on October 6, 1975, is the document in which the
EPA performance specifications for continuous monitoring systems were
promulgated. An outline of this document is given in Figure 1. Several points have
been revised by subsequent publication in the Federal Register, and major revisions
were proposed October 10, 1979, and January 26, 1981. However, those revisions
were not yet promulgated as of December 1982.
The October 6. 1975 issue of the Federal Register states drift limits and accept-
able error limits for monitors. But more importantly, that issue establishes the posi-
tion that the EPA does not approve specific brands of instrumentation or specific
analytical methods (in the case of gas monitoring) for source-monitoring systems.
This is in contrast to the policy of approving specific instrument models for con-
tinuous ambient air analysis. What it does establish, however, is the Performance
Specification Test. The EPA provides latitude in continuous monitoring system
design and application to allow sources to successfully handle individual problems.
The installed system must meet minimum requirements for instrument location,
drift. accuracy, and other specifications.
8
-------
40 FR 46240
Oct. 6. 1975
Requirements for Submittal of Implementation
Plans - Standards for New Stationary Sources
I I
Part 51 Part bO
(page 46240) (page 46250)
Requirements for the Preparation, Adoption Standards of Performance for New Stationary
and Submittal of Implementation Plans Sources (Emission Monitoring Requirements and
(Emission Monitoring of Stationary Sources) Revisions to Performance Testing Methods)
(Preamble -John Quarles) (Preamble- John Quarles)
I I
A. Discussion of proposed revisions A. Background
B. General discussion of contents to revisions B. Significant comments and change. made to
C. Rationale for emission monitoring proposed regulations
regulations (I) on Subpart A - General Provisions
D. Discussion of major comments (2) on Subpart D.- Fossil.fuel.fired Steam
E. Modifications made to the proposed Generators
regulations (3) on Subpart G - Nitric Acid Plants
F. Summary of revisions and clarifications to (4) on Subpart H -. Sulfuric Acid Plants
the proposed regulations (5) on Appendix B - Performance
G. Requirements of States Specifications
I I I I
Appendix P Su bpa rts App,'ndix B
Pruft'duTCS I\tinamum emission (amendments and Pcrlt)Tmal"HC
monitoring additions) ~p('rifi<:alioll' (added)
requirements
(page 4(247) (page 46247) (paj{e 46254) (page 4fi259)
Figure 1. Outline of 40 FR 46240, October 6, 1975.
Once it has been determined that a facility is required to install a continuous-
monitoring system for opacity or for a specific gas, a decision must be made as to
what type of system or instrument will best satisfy both the EPA performance
specifications and the needs of the plant. The Federal regulations do not require or
recommend a specific type of instrument or system. The performance specifications
give the general characteristics expected of an instrument and clearly define pro-
cedures for checking the installed instrument's performance. These methods are
given in Appendix B of Part 60 of the CFR. An outline of the contents of Appendix
B is given in Figure 2.
9
-------
Pt'fIOlllldll( (' Spt"l-ificatlun 1
IT dns.1Il15\OO1t'1t'r Systt'ms
(P"g< 46259)
P('rrorm~nct' Spenfication 2
MonitoR of SO. .nd NO.
(P'V 46265)
Pt'rformanc(' Specification 5
Moniton of CO, and 0,
(P'V 48268)
Continuous mnnilonnK !Oy\tt"m
pt"rformann" sPl>( Ifll- dtlons
II)
1'1Innpai .ll1d dpplicdhiluy
Principl~ and .lpplic.lblli(y
Principl(' and applicability
data anaiys1s and
Figure 2. Outline of Part 50, October 6, 1975 FR.
Figure 2 shows that there are performance specifications for opacity monitors
(transmissometers), S02 and NOz monitors, and CO2 and O2 monitors. Each
specification discusses the installation requirements, the levels of performance
expected of the instrument system during a one-week operational test period, and
the statistical methods of analyzing the data obtained during the test period. The
specifications for opacity monitors include a number of design characteristics that
those monitors must have.
In summary, Pan 60 of the Code of Federal Regulations incorporates the
requirements for the continuous monitoring of designated new stationary sources.
The manner in which continuous-monitoring systems are expected to perform after
being installed on a source is given in Appendix B of Part 60. Existing sources are
regulated by the States, and continuous-monitoring requirements for existing sources
must be established by each State.
Since there are many more existing sources than there are new sources, continuous-
monitoring requirements for existing sources affect a larger number of facilities than
do monitoring requirements for new sources. There is a significant difference,
however, between regulations for new sources and regulations for existing sources. As
part of the Clean Air Act, the States regulate existing sources. The Federal Govern-
ment regulates new sources, unless this responsibility is delegated to the State. The
10
-------
States, however, may not arbitrarily set standards and regulations. They must follow
certain minimum requirements established by the U.S. Environmental Protection
Agency.
The Federal requirements that each State must follow when drafting regulations
for continuous source-emission monitors are found in Title 40, Part 51, Appendix P
of the Code of Federal Regulations. Once the State regulations are approved by the
EPA, they become part of the State Implementation Plan (SIP). The SIP is a con-
tinually evolving document establishing the procedures through which a State plans
to meet the ambient air quality standards set by the EPA and other goals established
by the Clean Air Act.
The requirements were published in the October 6, 1975, Federal Register, at
which time one year was given for the States to submit continuous emissions
monitoring regulations as part of their SIPs. Figure 3 outlines Part 51 of the October
6, 1975, Federal Register.
There are presently four source categories for which States must draft continuous-
monitoring regulations: fossil-fuel-fired steam generators, sulfuric acid plants, nitric
acid plants, and petroleum refineries.
Several exemptions apply to existing sources but do not apply to sources covered
by the New Source Performance Standards. The exemptions were allowed so that
undue hardship would not be placed on existing facilities or on facilities that will be
retired within five years (five years after inclusion of the source category in Part 51
Appendix P). Also, States are required by EPA to monitor only sources that have
emission standards for S02, NOx, or opacity for those source categories in their SIPs.
The aim in Part 51 is to have States develop regulations that will be fair to existing
sources. Sulfuric acid and nitric acid plants are required to install monitors if they
have production capacities of greater than 300 tons per day. Catalyst regenerators at
petroleum refineries need to monitor opacity only if they have a feed capacity of
greater than 20,000 barrels per day.
In contrast to new fossil-fuel-fired steam generators that burn oil or coal, existing
fossil-fuel-fired plants are required by the States to monitor S02 emissions only if a
flue gas desulfurization (FGD) system is used, Also, for existing plants, NOx emissions
are to be continuously monitored if the plant is within an Air Quality Control
Region (AQCR) that has a control strategy for nitrogen oxides, if the source has a
heat input rate of greater than 1000 x 106 Btu/hr, and if the source emits nitrogen
oxides at levels greater than 70% of the State's NOx standard.
For developing continuous emission monitoring regulations, States have
mechanisms other than the SIP regulations mandated by Appendix P. Many agen-
cies currently use permits, direct compliance orders, variances, and their discre-
tionary authority to require the installation of monitors on sources not specified
under Appendix P requirements. In many cases, regulations developed under these
procedures are more stringent than are those in Appendix P. States are increasingly
using monitoring systems for compliance purposes, and in some cases monitoring
systems are legally used as enforcement tools.
11
-------
Part 51
. (~age 46240)
R~ulr~~nu for t e Preparation. Adoption
and Submittal of Implementalion Plans (Emis-
sion Monitoring of Stationary Sources)
(Preamble-John Q.uarles)
A. Discullion of proposed revisions
B. General discussion of comments to revisions
C. Rationale for emission monitoring regulations
D. Discussion of major comments
E. Modifications made to the propos~d r~ltUlations
F. Summary of revisions and clarifications to
th~ proposed regulations
G. R~quirements of States
I I
. - - I
)#'( tj(Jr, S I 111 A Pp<'IIJ,:\ I'
~(((,(,rl °d I (amend~d)
(am~nd~d) Minimum Emission
Source Surv~illance Monitoring Requirements
Add~d D~finitions Proc~dures
I
11.0 11.1 11.2 11.$ 11.4
Monitoring
Pu rpos~ Applicability Ex~mptions Extensions system
malfunction
12.0 12.1 12.2 lu 12.4
Min.mum Fossil-furl- Nitric Suit uric Fluid bed catalytic
monitoring fir~d st~am acid acid cracking unit catalyst
requir~ment g~n~ratOrs plants plants r~generators at ~trol~um
refin~ries
13.0 I:u 15.2 IB 1~.4 13.5 1~.6 I~. 7 1~,8
Mmlmum P~rformanc~ Calibration Cycling Monitor Combin~d Zero
sprcifications s~cifications Exemption gases times location eff1u~nts and Span
drift
14.0 ~.9
:\Imimum
data Alternative
requir~ments procedures
and
requirem~nts
r--1;o
Data
reduction
--'b 0
Special
.\H\~\lkr .H1\)I\
Figure 3. Outline of Part 51, October 6, 1975 FR.
12
-------
Once it has been established that an existing source must install a continuous-
monitoring system, the instrument specifications, the data reporting requirements,
and the Performance Specification Test requirements are the same as for new
sources. In fact, Part 51, which gives the minimum requirements for the State
regulations, states that each State plan must incorporate, as a minimum, the con-
tents of Appendix B, Part 60 (which gives the performance specifications for
monitoring systems on new sources).
A bout Thu MantUll
This collection of documents is intended for use in APTI Course 474 Continuous
Emission Monitoring. The manual includes selections from the Code of Federal
Regulations and from Federal Register publications from October 6, 1975 to
December 1, 1982. Documents included in Section II are not segregated by topic
and are not classified other than by the date on which they were published.
Your course instructor will refer you to specific items in this manual as you pro-
ceed through the course. This manual will also serve as a useful reference document
for your further work with source-monitoring systems.
James A. Jahnke
13
-------
Section I
Selected Information on New Source
Performance Standards
A. Federal Standards of Performance for New Stationary Sources of Air
Pollution-A Summary of Regulations by Naomi Durkee, U.S.
Environmental Protection Agency. (Reprinted by permission from the
Air Pollution Control Association, 1981-1982 APCA Directory and
Resource Book, Special Annz'versary Edztzon. APCA. Pittsburgh, PA.)
B. Summary of Proposal and Promulgation Dates for NSPS Source
Categories.
C. Selections from the Code of Federal Regulatz'ons (CFR), Sections 40
CFR 60.5 to 40 CFR 60.14.
15
-------
FEDERAL STANDARDS OF PERFORMANCE FOR NEW
STATIONARY SOURCES OF AIR POLLUTION
A Summary of Regulations
Naomi D. Durkee
U S Environmental Protection Agency
In order to make the information in the f','dera/ RI'~I"tl'r more ea,Ii:, a,'.
l'es"ble. a summary has heen prepared of Federal standard, of pertor.
mance for new stationary ",urees of air pollution. The standards 01 perfor-
mance promulgated hy the Environmental Protection A~ency In the peri.
od from Decemher 1971 throu~h .June 1981 are presented in tahular form.
In the AUKu,t 19,9 '''"', "I .JAPC.I,
Sh,rlev K. Tabler "f the \ S Envir"n.
rnpntal Prott>LtIl>O A~PI1(~ ~ EPAI...um-
marized the F,'deral standards ,,' per.
formance for new statIOnary ...our('e~ lIt
air pollutllln promulKated bv EPA lor
the period from Del'ember 1971 throuKh
.Iune 1979. The summarv was developed
to provide d conCise reference for people
to use when looklO/:: lip J particular
:-;tandard. The summar~' ha~ proven to
he very useful to many Indl\'ldual, and
Kroups who work with Federal standard,
ot performance tor new slatlOnar\'
:-OUTl'fS of air pollution. The foliov.lI1g
....ummary. prt'sentt'd again in tahular
lorm, I~ an update ot the AU/.{lIst I ~J-;!J
information and mdudes those EPA
"'Clndards prllmul~aled lor the pt'rlod
frCln1 l)erpmlll>r 1971 thr(HI~h.JlIne l~'xl,
It 11H'ludes t he l'at{'~ories of .....}tlOndrv
..,mln'rs. the atfe<:ted fal'liltle!'> tn whIt h
Ihe ,tandards apply, the polllltanb
rt!Kulalt'<1, tilt' It.>vt'ls to whlrh they mU:-.t
1Jl' controlled ,lI1d the req\llrt'menb lor
monltl.lrll1~ t'ITH~~\()n~ ,md tl(Wratln~
p.lramt'ters, .\lthnu~h ,h1mlll\:--lratl\P
t~pt) .1Int'ndllwnts Ill', .llIthllrl{\' 1'11.1-
tlon addition.... .1IHll'han~t".... ,lIld Cllrrt't'
lion notices) to the standard!'> Wt'rp in-
duded In the IIri~inal ~lImrnar\, the..w
ly pe amendments are not IIldudt'd In
the update, All otht'r reVISions .He In-
cluded.
The standards are issued under :-t't'-
tllln 111 of the Clean Air .-\ct. 'IS
:'vb [)urkt'E.' IS III (he ~t.lndclrd~ ()t'
\'t>lopment Branch. ()trICE.' 411 AIr
~1uahty Planl1lng and "'t.lnd.url,~
(I S Envlronment.11 Prult>dlnn
"gem'v. Ht'...earch TrHln:..;lt' P.lrk, ~('
:2';'';'11.
amendHt. ,}nd appl\' 10 I1t'W, modlfit:'d,
and rel'onslrul'tpd :-.tatlonary ....ourees of
air pollutIOn The ~tandard:-. retlect Ihe
deKree lit t'ml"~llIn IlInitallon dt:hlevahle
through the ;tpplkation of t he best
dem()n~t rated te(:hnoloKlcal system ot
contlTlllOUS eml~SI()n reduction. consid-
ering the cost and any nonair quallt~,
health and en\'lftlTlmental Impact and
energ~' reqlllremt'nts,
Retore up\'e!oplIlg "tandarn... for a
partH.'ul.H "ourct' calt:'~ory'. EPA mllst
first Idt'ntll\ the pollutant., emitted Lind
determlnt:' that the\' contribute ~Igntfi-
caotly to air polltilioll whh'h endanger...
puhllc healt h or wel!are, The standards
are Iht>1l de\'rIHpt-'d and propIJ"t'd In the
Fj'cfj'fa! Un!h{.'f .\lter a period 01 tlmp
lusuallv tin d.lv",,' dUrln~ whllh the
puhhl' h 111\ Ih'd to ...uhlnlt ct!mmt:'nl~ on
the prcJpll,,~d. ,Ipprllpflate reVl~lOn~ are
made tll Iht' rt':':IILII\ClI1:-' .md tht'\' Lire
pr"mtll~,IIt'd In tIlt' F"ti"fat /(I'J..!./,fl'r To
llll' "'Udl a prilinukat lOll. It I" t'IHlH1Wil
tll relH I"~ It 11\ \1I11H1\t' .IIlII 11<11.:t' num-
her. It'. ,~Ii Fit ~ I."I7ti, \\ hlch ITwans
\'olul1lt' ,\ti, p:JJ.!t' .! 1:..;71; 11\ lilt.' "','d.'rn!
UI'!.,'I,tl'f rlw (.1111., gl\(''''' ...1It'Il rt'It.'fI'nL'e~
lor tilt' prllp"",.!. promulgatloll. ..1I1d
...uh"t'l{lIt>nt rt'\ t"lt,rb 01 l,,\t'h ...tanllard
lISted
Dnlt:' .J ~.;ear. ,111 regulatlon~ Whh_h
have hel'11 pllhlhht:'d In I ht:' /.','d,'ral
Rt"J:l..;{ef dUrIng Ihat \P.H .Ire t odilif'u
lor IOllll:-.I.111 In tht, ('I,dt' 1,1 ~\>deral
Rt:'gul.ltIIHb I('FH) ()nlv thf' rf:'gllialions
are l'C)(ilfit'd, the pr(>amblp... \\ hich ap-
pear with tht' reglliallolh III the F,'d,'ra!
Rt>~I'II'r .Ire Iwt II1t'1l1dl>d In tht' ('FR
The C FH 1:-. l1le Il1lht:' lahle
head inK tu ~'I ('FH Part ';[1.
Tht' t.lhle Ii...h .111 ...tJndanh ql IH-'r-
Inrmance profTlUlgi1lt:'d thrllll~h '!lIllt'
19H1 The ('I)mplete rt'j.!ulations for mo...t
ot the:-.{> ....tandard:-. drt' incluul'd 111 Ihp
CFR whlth W.h re\h(~d a., td ,1111\, I.
l~~(), ,Jnd ('ontaln:-. Parts 110 to \I~' :\11\
lutllrt-" rt'gulatillns prl)po~f'd or prllnlul
~ated will aplw.u IT1 t h(~ F,'d,'ra{ H"J.!I,,(t'r
t pulJll">lwd ddd\' t'\l ept Sat urda\ and
Sunda\'1 ,Hld \\'111 h... I'oddit:'d 1IIIhl' .In"
nual rp\ 1"\fIn II' lhl> (' FH. .\I1\'III1P \11" 1...1\
lug 10 "lIh~(-'flhe tf)' he F,'dl'rfllll,'!!,,(, r
or purch;bP thl:' ('FH "hould t'ontal-' ,111'
~lIpt'rJnlendent 01 ()Ot urnt'llh" t':-;'
Covernnlpnt Prilltlng Onll'l'. \\ a"hlt1g-
ton. D (' '2t1-!o'~
~t..lndard... lor tilt' 11I1IC)\\IIl~ rt-->~HLI-
tlOI1-.. h,l\e ht't'll pr!!po"t-'d ,llld wtll Ill'
pron1ul:.:at(>d In the TWXI n'ar: ph~""ph.I\"
rf)l.k plant:-.. Ip,HI .Il Id hatl('f\ 1TI:lIWI.It
tlJr1l1~. \"()(' Irom "::holllH' 1.1111.. trill k
loadlllg rack:-. and hulk ga:-.(,JIt1t. tl'r III I
nal:-., 1;.Hge appllanl t:' "lIrl;)I.< I (I,JllIl;'"
\'OC fU~ltln" pml""I"n .,our....... In ,hi>
~ynthptlc organIc I hemltal:-. rnanut..H
luring Indu~trv, fTIt-'tal lod ~ljrt.tt I'
(oatlnl::", ,j""phalt prlll't''-''lllg ,lOt! ""ph,dl
rooting manutactlJrl:'. oq.!:.trIll' "01\"111
deaner..., pt:'trIJlp\Jm Ilqlll<1 ..,tlJr.I~I' \I.~
:-,pl~--t'q\lI\-,dt-'rll'~' dt'tt'rmlll:lllll1l. ,II)(!
Intern,!! l.Jrnhll~IH'n l'llgllll"-
Thl'- ...umnl.1f\ I'" prq\\dt-'d.b ,I Iplll k
rplert'rltt' lInk ,Ine! I~ nlll 1~111t' Ibl,d !"r
pnfOrLf"menl "Ilfp!!'-t'... I'lhl-...t< rp!t'r ,,,
the F,-lifTo/Un!"!f f 1""~IJf".., II I!t.d III ,1.,-
tlr"t t'.dumn II! thle' Lihlt>1 j"r, ornpl,.!t>
dt:'t.HI~ ton(yrnmg d ...tandard
,:. ~ -~ .:.
-------
Standards of Performanc~-40 CFR Part 60
Source
cat.gory
",onllOfI"O
'equlf8meftt8
Suhpart 0:
Fo~...il (u(>1 fired
,tram lItenl'rator~ >7.; M\\
ht',iI mput I > ~:,~ I million
Htulhrl
/'rr'fH,,,.d
, I~ ~II'!I; FH 1,,70:11
J'r"nll,:'l!(u,'d
1 ~ ~ I, '71 I.H, FH ! IX7h I
U'TI'f'ci
"7 ~t; '7'2 cr; FH 1-t~7: I
h'l-t/"74 L',lI FH. '.!O";,901
J'III/';',., i40 Fit '2XO:1I
111'1) 7:1 !-tl! FH .Ul~~ol
.... 1..,/';-;- I L~ FH 41 J:!21
L!,/1.i/';'-; I t~ FH 61:1:\";"1
'I'i/-.. l-t ~ FR \12";'111
A"ected
'ocllll,
Pollutant
Eml..lon 18ve'
U.1O Ih/milhon Btu
2W'j- I~:(', 1~lr n Olm'hrl
I '20 Ih/n\lllliln "HI
O,io Ihmllilion Htu
(U;Olh,'rmllulII Bill
Exempt
Oll\lb/milltonBtli
'211('"( 12il"'"( tOf 6 mm/hn
O.RO Ih/million Htu
lJ .\0 Ih/mlilion H1u
(I '20 Ih/mlilion ~lu
No requirement
C'nntinuou..
C'onununus
('ontlnuOU5
No rf>quirf'ment
Continuous
('Clntlnuuu~
C"ntlnuou"
('ont IIlUOU'"
Su bparl Da:
E'...ctric ulilit~, lileam >
Jtcneratinlt unib >-;0", \1W
hf'a! Input t >:!'-tll nulll"n
Hllllhri
J'r'lfJ'I\,'d
'I 111"';")0...' (FH 4~1-141
J',,{,nllll~nll'd
'j:11 "';"!'I-U FH :tl;,I"1I1
Cual ,fired bOiler!'"
ParT Iculate
Opal'it."
SO,
lI,(I;\ Ih:milllOn Htu
:!O""r 1:!7'( IlIrf, Inmihrl
1.20 Ih/01l11l01l Btue!
and 94.1", rt'dul'uOI1,"
PUP})t -;our; rt>dUt'lIolt
when t'ml"'''lol1~ IIrt'
Ie.... than II nO
Ih/mlllllln Hlu"
IU;U Ih/mlilion Htll
O,,:;('lh.'1I1111111O Htll
O}tlllh, million Blu
Expmpl
O.O~ Ih/miliion HilI
2()I"; Cl7f'( tnr6mlll'hri
U 80 Ih/million Rtll
and 9(1('( rt'ductlUn"
or
0.20 Ih/mllhon Hlu
Ino re-dl)ctlllil
re4~lIrt'mt'nt )
o.;ullI)imdhon Htu
0.211111/mIIIl01l Htll
NCI rpquir(>mrnt
('lint I IIUOU'"
('"otIlHltlU"
lllmplmnct"
Coni muou~
l't'mpliancf"'
No reqUlremrnl
('onllOuou...
Cuntlnuous
('omlll!ancf'
(.'untlnUCtu...
c11mpI13m.(.f
ContlOuou~
I'c'mphann'!
Suhpart E:
Incinerators
1>'iOtun..,da\"
No rPIIUIrt'IIIt'nl
""',p,,,..d
~ 1"';" :11.H~FH l:j;O:\1
""(Iffltlleuted
I:,U~:V;-t 1:\6 FH :.!~!-\:hl
R{'(I'f'd
,; H : ~ I \~ FR 211:~'j 11
~O,
Anthrdl'llt',
Rilumllltlu!-,
or Suhhllu
minouJi' ('oal
LI~mlf>(
011 or gas-flrrd
boilers
MUff' than :!,-/~
('oHI refusE'
Partll'UlalE'
Opacity
SO~-oi I
NO.-lIil
NO, -~.,
O.tlM Io:rdi"ll ('orrt'l'lt'd
lu I:!"", (.'(1
APCA
{'(,;iI-fired hodt'r...
land (:lIal-d£>rlved
hH,I..1
Particulate
OpaClt\'
SO-
(}d or ga...flrt'd
tltnlE'r..
~()JI£
Anthranu"
Altllmllltlll!'
SuhhllumlOous
('U8)
C'lIal-df'rI\pd
fuels and
hha~p 011
Mort" Ihan 2,~',
cllal rei use
Partl('uIHtt'
Op8nh
SO,
~Or ~oil
NO", -KaJ.
I nnnpralure;,
Partll'ulalt'
148
18
-------
Sow.. AHOCIod Monitoring
cateoory 1..IIHy Pollutant EmlukNIl8vei requlr.m.n"
Subpart F:
Portland cement plants Kiln P.lrtlculate t1 :lt1lhiton :--';0 ft'4U1rt'mt'Jlt
Prnp()"ed Opacity '200'(' ;\in ft"QUIft>ment
h/17/711~6 FR 1570:n
Clinker cooler Particulate 0 10 Iblton ;'\in requlrt"ment
Promul#:ated
12/2~!7l 1 ~6 FR 248761 Opacity 100', :\11 reqUlrt"ment
Rf:'l'lsed Fuglt",e Opacity 10% ~o requirement
6/14/74139 FR 207901 Emission pOints
11/12/74139 FR ~98741
10/6/75140 FR 462501
Subpart G:
Nilric acid plants Process equipment Opacity 1001" No requirement
Proposed NO, 3.0lh/ton ('(lntln\J(Ju~
8/17/711~6 FR 15703)
Prnmulf.!ated
1,12:]/711~6 FR 248761
Rpl't.'wd
:J/:!;J/7:1 (:18 FH 1:15621
0114/74 (:19 FR 207901
111/0/75140 FR 462501
Su bpart H:
Sul(uric acid plants PruCt....~ equipment SO, 4 t1lb/ton ('"ntlnlJou~
Propo.-ted
H117/71 1:16 FH 1570:\J ACId mist 0 I.~ Ih/tun ~n rf>QlILrement
OpaCity lOr;. :'\1'1 req\lIrt'meTll
[J",muiJ.:atf'd
12/2:1171 (:16 FR 248761
Hf't'I,,,'d
.'>. 2:1/7:11~8 FR 1:15621
'i; 14/74 1:19 FH 207901
10/617,,140 FR 462501
Subpart I:
A!iphalt concrete plants DrYt>r~. screenln~ Partll'ulatt. II O~ K./dscf ~o rpqlllft'mt>nt
..lOd Wt'IKhlng ~90 mK/dscm)
IJrfJpIJ..wd "ystems, storage,
';,11 17~ Cl8 FR 154001 Iran~ler, and Opaclt) :.!11t""r '0 ff'qIJlff'fnl'lll
loading "y<;tems,
I'romul~act!d ..tnd dust handhnK
: .'1741:19 FR 9:IIJHI t'qulpment
H"luf'd
111/',/7.'\ I~O FH 4li25111
Subpart J:
Petroleum refineries Fluid t,atalytlc Particulate I 1\ Ib/lOliO Ih :\n feqlJlrf'menl
crackln~ Unit (If (oke hlJrn.oll
JJrl'pt,.'f'd 1.:3tal\'<;t r{,~E'nerator
.' 11/7:1 (:JH FR 1040lil Opantv H)r;. H, mln E'XPmptlOnl ('IJOtlIlUOII"
J'''"muh!att'J
IHI74 1:19 FH :I:IOHI CO 111\:,', ('ontlnIJ!Jlh~'
Fuel g:ag I.:umhustlon ";(L II jlll{r/th.d ('ontLnllf.lh
H"I'I.'wd device!'!
10/',/-;';) t HI FH 41)2~0) H."; '2:\(1 mg/d", rn ('IJnllnIlIJII:o.h
,: ~.'!i'7 ( 1'2 FR :t!4:.!1;)
\ 1,,;7H 14:1 FR IOHlilil Claw. "ulfur :-;n ~ 0,02.1)"', lat tr, t '"ntllllllll'"
.: 1~/7914-l FH lJ4HOI rel'O\'t'r\' plants ox\'genl
Hedu('t'rl ..ulfur () U.\om(l ~ at UC11( (onllTltllJtI"I,
t'ompounds oxygen)
plu> H,,, O.!HJIW"r (at U""( ('nnlLnwJu..,h
oxygen I
149
;.p(;.
19
-------
Source Anectecl --.
category ,..II"y Pollutant E- ".al .....-
Subporl K:
Storage yellels for storage tanks \'OC Equipment No requirement
p~troleoum liquids >40,000 gal bUI nol standard"'
(!)n...tructed afteor >65,000 gal capacily,
6/1l/';'~ and prior to constructed after
3/Sn4
1 l0;),000 gal. constructed
6 1I'~:1138 FR ) 54IJn, after 6/11n3 and prior 10
5/19nS.
Prt,mul1!otPd
3/8', 4 <:1~ FR 9308,
Rell,ed
4:1~ '~4 13~ FR 11~,f,'
0/1.a/","4 1:~9 FR :!07901
",;~/X(l t.a;-f FH 2:'\:\7:\1
Subpar. Ka:
StoraKP yellel, Stora~t' Vessel \'Ol' Equipmt'111 NOI1t'
for petroleoum >4IJ,Um ~al capa. Standard"
liquids cunstructed cltv constructed
All.r Ma, 18,19,8 afler 5/1Sn8
PrlJpfJ!\f'd Stora~f' Veossel
.;!J~:,~ 14.1 FR 21610' <4:!n,OOO ~al capa-
city for petroleum
Pmmul~ated or condeonsatf' stored.
4/4/80140 FR 233731 processed, or
trt'atf'd prIOr to
custod\" transfer
IS nut ~n affected
facility and IS
exempted
Subparl L:
S('(:ondary lead Hf'vertwratory and Particulate 0.022 ~r/d"f No rf'qulrf'ment
smelters hla~l furnace"- 150 m~/dscm 1
PrrJpfl','d
6/11/,:\ ,:" FH 1,,41161 Opaclly 20"', No requir~menl
Pot furn8cf'~ Opftcit, 1(1"', Nu requirement
f'rumulJ.!otl'd
\"/,4 I\~ FH 9:1081
h'1'11,,'d
I 1-:"";-1 \.\~t FH 1,1';'~tlf
100Ii/"j'-II~1I FH .t()~,~1I1
Su bpa rl ~I:
S("conda" bra.. and Rf'\'erbrr8tor~ P8rllcu~8tf' 0.022 ~r/ds('f Nil rpquin-mrnt
bronzp plants furnace" 1 !;(I m~/d.cm 1
Jlrllp.",.J
6'111,:1 1,- FR I f>401i , OpacilY 20% Nu reqlllrf'ment
Bla.t and Opacily 10", No requirement
Prnmulpcl£'d elf'ctric furnaces
'\ , ,41\9 FR 9308,
Rf'lHif'd
10/6/i~ i.t! I FR 462:;0)
Subparl N:
1 ron and steel plaDh Ha....1C oxygen Particulate 0.022 ~r/dscf No requirement
process furnaces 150 mg/dscmJ
PrllpPH'd
fi/l1/~ \ 118 FR 1.-,41)(,' Opacity 10"< Scrubber
pressure
Ioos
Prllmu!L.'t.I!('d
:~/I'\, 741:\9 FR ~nO>-l1 2CYi(' onct" each Wateor prf's~urp
productiun
R('('I,t'd cyelf'
4,1:1 '","... I.t~ FR 156(KIJ
A.PCA
150
20
-------
Sourca A"8Cl8CI -.......
calegory 'acillty Poliulenl 1- ..,.. requkementa
Subpart 0:
Sewa,e treatment Slud,e incineraten Particulate 1.30 lb/ten Masl or volume
plante of .Iud,e. Ma.. of
municipal .olid
waste, ir any
Proposed
6/11/73 (38 FR 15406)
Opacity 20% No requirement
PromulRated
:1/8/74 (39 FR 9308)
Revised
4/17/74 (39 FR 13776)
.'>/3/74 (39 FR 15396)
10/6/75 (40 FR 46250)
11/10/77 (42 FR 58520)
Subpart P:
Primary copper Dryer Particulate 0.022 gr/d.er No requirement
smelters (50 mg/d.cm)
p,.opo~ed Opacity 20% Continuous
10/16/74 (39 FR 37039)
Roaster. smetttng 502 0.065% Continuous
Prnmul~ated furnace," copper
1/15/76 (41 FR 2331) converter Opacity 20% No requirement
RevISed .. Reverberatory
2/26/76141 FR 8346) furnaces that
11/1/77 142 FR 125) process hlgh-
Impurity feed
materials are
exempt from S02
.tendard
Subpart Q:
Primary zinc smelter! Sintering machine Particulate 0.022 gr/docr No requirement
Proposed (50 mg/docm)
10/16/74139 FR 37039) Opacity 20% Continuous
PromulNated Roaster 502 0.065% Continuou8
1/15/76141 FR 2331)
Opacity 20% No requirement
Subpart R:
Primary lead .melte.. Blast or reverberatory Particulate 0.022 IIr/docr No requirement
furnace. sinterinl 150 mll/d.cm)
Pr/'poHed machine di.charge end
10/16174 (:19 FR 37039) Opacity 20% ContinuoUi
Prnmulated Sintering machine, S02 0.065% Continuou8
1/15/76141 FR 2331) electric smelting
furnace, converter Opacity 20% No requirement
Subpart S:
Primary aluminum Potroom group (a) Total fluoride. 2.0 lb/ten No requarement
reduction plante la) Soderberg plant
Opacity 10% No requirement
PrnptMed
10/23/74139 FR 37729) (b) Pre bake plant I b) Total fluorides 1.9 Ib/ten No requarement
PromulNated Opacity 10% No requirement
1/26/76 (41 FR 3825)
Anode bake plants Total fluorides O.llb/ten No requirement
6/30/80 (45 FR 44206) Opacity 20% No requirement
Subpart T:
Phosphate fertilizer Wet process Total fluorides 0.02 Ib/ten Total preaBure
plante phosphoric acid drop across
Proposed process
10/22/74139 FR 376011 scrubbing
Promulgated system
8/6/75140 FR 33152)
151
:21
-------
S-ce A_'" -.......
c.18IO"J 18CIIIy -.... E__ -
Subpart U: Superphoophoric acid Total nuorides O.Ollb/ton Total presaure
drop acroos
procell
scrubbing
.)'Stem
Subpart V: Diammonium phoophate Total nuorides 0.06 Iblton Total presaure
drop across
proceu
.crubbing
system
Subpart W: Trtple superphoophate Total nuorid.. 0.2 Ib/ton Total pressure
drop across
proce..
.crubbing
"ystem
Subpart X: Granular tripl. Total Ouorid.. 5.0 X 10-' Total pr...ur.
.uperphoophate lblhr/ton drop across
process
scrubbin~
Ry~tem
Subpart Y:
Coal preparation planta Th.rmal dry.r Particulate 0.031 gr/doef T.mperature
10.070 K/doem) scrubber
Propos.d pre.lure lOB.
10/24/74 (39 FR 379211 Water pressure
Promuilloled Opacity 20% No requirement
1/15/76 (41 FR 2232)
Pneumatic coal Particulate 0.018 gr/dser No requirement
cleaning equipment 10.040 ~/doem)
Opacity 10% No requirement
Pr~inc and Opacity 20% No requirement
conveying equipment,
storace systems.
transfer and loadmg
system.
Subpart Z:
Ferroanoy production Electric .ubmerged Particulate O.99lb/Mw-hr 10.45 No requirement
r.cilitin arc (um.eft kK/Mw-hr) ("hi~h silicon
aUoys") 0.51 Ib/Mw-hr
PropOI.d 10.23 kg/Mw-hrl (chrome
10/21/74 (39 FR 37469) and mangan... alloys)
Promuillol.d
5/4/76141 FR 184971 No visible emiSSions may Flowrate
escape furnace capture monitortng
system in hood
RE'l'Ued
5/20/76 (41 FR 20659 I No vilible emiuion may Flowrate
Heape tapping sYltem monitoring
for >40% of each in hood
tappinK period
Opacity 15% Continuous
CO 20% volume basis No requirement
DUit handling Opacity 10% No requirement
equipment
Su bpart A.A.:
I rOD and .t..,1 Electric arc Furnacel Particulate 0.0052 gr/doef No requkrement
plant. U2 mg/d.cm)
PrOpOlM
10/21/74 (39 FR 37465)
Promuillolrd Opacity
9/23/75 (40 FR 43850)
(a) control 3% Continuous
device
(b) .hop roof 0, except Flowrate
2O%-charging monitoring
40%-tapping in capture hood
Pressure
monitoring In
DUit handling Opacity DSE system
10% No requirement
~quipment
APCA 152
22
-------
Source A1I8Ct8d Monllorlng
category 'eclilly PalM.... Emlalon lewel requlrenwn"
Subpart BB:
Kraft pulp mill. Digester, washer, Total reduced ;) ppm by vulume on a Contlnuoush
I Kraft pulpong evaporator. condensate sulfur (TRS) dry basis. corrected
operations within stripper. or b~8Ck to a specific oxygen
neutral sulfite liquor oxidation systems content
semlchemical
pulping mills) Straight kraft TRS 5 ppm by volume on a Conttnuoush
recovery furnaces dry basis corrected
Proposed . to 8% oxygen
9/24/76 (41 FR 42012)
Cross recovery TRS 25 ppm by volume on a C'ontmuoush
Promulgated furnaces dry basis, corrected
2/23/78143 FR 7568) to 8% oxygen
Revised Smelt tanks TRS 0.0084 glkg black Conttnuoush
8/7/78 (4:1 FR 34784) liquor solids (dry
1/12/79 (44 FR 2578) welghtll0.0168
Iblton liquor solids
Idry weight)
Lime kilns TRS 8 ppm by volume on a Continuoush
dry basis. corrected
to 10% oxygen
Any recovery furnace Particulate 0.10 gldscm No reqUirement
10 044 gr/dscO,
corrected to 8%
oxygen
OpacIty 35% Continuous
Smelt tanks Particulate 0 1 glkg black liquor Continuous
solids Idry welKhtl measurement of
10.2 Iblton black prtssure 1059
liquor solids (dry when USing a
weight) I scrubber
emission
control device
Lime kilns Particulate 0.15 g/dscm ,0.067 Continuous
gr/dscn, corrected measurement 01
to 10% oxygen when pressure loss
gaseous fossil fuel when using a
18 burned scrubber
t'misslOn
control device
0.:10 g/dscm 10.1:3
~r/dscfl. corrected
to 10% oXYKen when
liquId fossil fuel
15 burned
Subpart CC:
Glass Mfg. Glass melting Particulate Rates vary None
PlaDts furnace
Propo...d
6/15/79 (44 FR 34840)
Promulgated
10/7/80 (45 FR 66751)
PetitioDs Cor
reconsideration
have beeD filed
153
APCA
23
-------
Sourc.
e.l....,
Subpart DD:
Grain elev.ton~,J
I'rup"",..d
1'1 {!~~ I~~ FR 28421
" .'~ '~~ 1~2 FR ~22641
Pr11ptJSai
'l.I'ppnded
, ',~" I~;\ FR ~4;\491
Prupu!ial
reinstated
PrfJn1ulRoted
Mf'{ '~h 14,\ FR ;1~;1401
""-
'ocllH,
All facihtles listed
below
Truck loading stations
Truck unloading stations
Bar~e or sblP loadin~
stahuns
B8r~(> or shap
unloadint( slatlOns
Railcar loading
statiuns
Railca, unloadlntt
!'>lallun!'o
Gram dryers
-Column dryers \\'hich
bave perC~rated plates
with hole sius larger
tban ° 09~ incb
diameter
-Rack dryers with
screen filters COaflef
tban 50 mesh
Gram bandling
ope-fa lIOns
Potlutant
Particulate
Opacity
Opacity
Opacity
Opacity
Opacity
OpacIty
Opacity
NonMorIng
E_"'" ""'-
0,01 grldlcC No requirement
10% No requi~ment
5~ Nt! requirement
20% Nu fe-qulrement
EquipmentSlandard' No requirement
5'1', No requirement
5cr" Nu requirement
(1"", No reqUirement
~
No requlremt'nt
Suhpart GG:
Galt Turbine.
hl'at '"put at pt"8k
luad ('qual III Of
~rt'.ttt'r 1han
111 -; ~ll!aJuules/hr
-IIMHI horsepower I
Simple and r.~en.
erative rycle Ral
turbines and the
Itas turbinE' portion
of a combmed cycle
steam/electric
gf'neratlnlt system..
PrllpfJ.'iird
(J( luher ;1. 197~ 142 FR 537881
Prc1mul1f8ted.
September 10. 197914~ FR 527981
Standard under PetitIOn to re-Vlew .
. I'ropu...ed ren"ilnn 4/1MHI t 4f1 FH 22()()5~.
NO,
so,
See 44 FR 52798
C'unlinuou~
monltorln~
uf watf'rlfurl
ratio
Momtof sulfur
and nltr()~en
content of
fuel fIred,
Rolary lime kilns
Revius the applicability of the ~t8nd.rd with respect II' InduAlrialltas turhines
0,30 Ib/ton
Scrubber
pressu re
10,,; Scrubber
liquid supply
pressure
Subpar. HH:
Lime manuracturinc
plants
Prf,pfl...rd
;}'J '';'j (.1~ F'R 2'2.!)061
IJrllmu!J.,'at£'d
:\'";' ';'~ I.&:l FH ~.r}21
Lime hydrators
Particulate
OpacIty
Particulate
10%
Cuntmuous
0.15 Ib/ton
Scruh'wr liquid
nny,
rale; Electric
('urn"nl
u..d hy
Icru bber
APCA
IS.
24
-------
_..
c..~
Subpart MM
Automobile and
Ligbt Duty Truck
Surface Coating
OperatioDi
Mod..
,..11IIy
PoIIuIMI
~ .....
-ortng
requlrernem-
Prime coat operationB
Guide coat operations
Topcoat operations
VOC
0.16 kilograms
of VOC per liter
of applied coating
solido from each
prime coat operation
Incinerator
temperature
(if applicable)
Propo.ed:
10/5/79 (44 FR 57792)
Exempted from these
provisions: operations
to coat plastic body
components or all
plastic automobiles or
light-duty truck bodies
on separate coating
lines.
1.40 kilogram. of
VOC per liter of
applied coating solid.
from each guide coating
operation
Promulgated:
12/24/80 (45 FR 85415)
1.47 kilograms of VOC
per liter of applied
coating solids rrom
each topcoat operation
Subpart PP:
Ammonium Sulfate
Mfg.
Ammonium sulfate
dryer w/in ammon.
sulf. mrg. plant
in caprolactam
by-product, syn-
thetic, and coke
oven by-product
secton
Particulate
0.15 kg/Mg
1.30 Ib/ton)
15'
Provide now
monitoring devices
or weigh scales for
reed material
streams
Monitor pressure
1088 across the
control device
Opacity
Proposed
2/4/80 (45 FR 7758)
Promulgated
11/12/80 (45 FR 748(6)
. Continuous monitors are used to determine e1ceu emi88iona only, unle.. noted u "continuoU8 compliance."
b Include. boilers firing coal/wood mixture..
, IC more than 25' lignite which was mined in North Dakota. South Dakota, or Montana is fired in a .lap tag rumace, the standard is 0.80 Ib/million
Btu.
d For SRC.I an 85' reduction requirement applies (24-hour average).
. Percent reduction requirement does not apply to facilities firing l()()% anthracite, resource recovery facilities firing leu than 25% foutl fuel
(90-day average), or facilities located in noncontinentalareaa.
, 30-day rolling average, ..cept where noted.
I Commercial demonstratIOn permits are a.allable ror: SRC-I (SO.) 1.20 Ib/million Btu and 80'!1. reduction (24-hour); FBC (SO.) 1.20lb/million
Btu and 85' reduction; Coalliqueraction (NO.) 0.70 Ib/million Btu.
h Not effective until monitor performance specifications 8re proposed and promulgated.
I Grain elevator terminala n.e., grain elevaton which have permanent grain storage capacity of over 2.5 mHHon bushels), which handle or process
wheat. corn, sorghum. rice. rye, oats, barley or soybeans.
J Grain storage elevatora at wheat nour mills. wet corn mill.. dry corn mills (human consumption), rice mills. and soybean oil extraction plants,
which handle or process wheat, com, sorghum. rice. rye, oats. barley or soybeans and which have a permanent grain storage capacity of over
1 million bushels.
, Marine leg enclosed from top to bottom of leg, with ventilation now rate of both leg and receiving hopper or 40 cubic reet or air per bushel of
grain unloaded.
m For vapor pressure 7~570 mm Hg, equip with floating roof, vapor recovery system. or equivaJent; for vapor preasure >570 mm Hg, equip
with vapor recovery system or equivalent.
n For vapor pressure 10.3 kPa (1.5 psia) but not 75.6 kPa (\ 1.1 psia) equipped with external noating roor with primary and secondary seals (see
Federal RegISter ror seal gap requirements).
or For fixed roof with internal floating type cover equipped with continuous closure device.
or For vapor pressure 76.6 kPa, equipped with a .apor recovery system which collects all VOC vapors and gases and a vapor return or disposal
system de.igned ror 95% removal by weight.
or equivalent to one of the above.
U.S. Program Status for Hazardous Air POllu,ant.
1.
Listed Under Section 111 (d)"
sulfuric acid mist
fluorides
total reduced sulfur
Candidates for 111 (d)
cadmium
trichloroethylene
perchloroethylene
methyl chloroform
methylene chloride
trichlorotrifluoroethane
Listed under Section 112"
asbestos
4.
beryllium
mercury
vinyl chloride
benzene
inorganic arsenic
radionuclides
Candidates for 112
acrylonitrile
coke oven emiasions
FY 81 Candidates for Action
ethyl~ne dichloride
formaldehyde
nickel
6.
vinylidene chloride
FY 82 Candidates for Action
epichlorohydrin
ethylene oxide
manganese
2.
5.
. u S Clean Air Act
Note Pollutanta lor which evtcience 01 carCU\OIeflJClly 18
eMifted .. b.t or ....b8tanual .enerally w.1I quahly for
h.tllll ... huardOUI pollutant uDder SectIon 112 Wherr
8V8dence II rDOft tentative. polh.lt.anta lUy b. lilted for
eoal.roI under SenJOn 111
R.pnnted from Ref..,.nce 4 On,\n&llOUrce EPA. 1981
3.
155 -156
APCA
25
-------
Summary of Propoeal and Promulgation Data
for NSPS Source Categoria
Subpart Source Promulgation Propoecd
date date
D Fossil.fuel.fired Steam Generators 12/25/71 8/17/71
Da Electric Utility Steam Generators 6/11/79 9/18/78
E Incinerators 12/25/71 8/17/71
F Portland Cement Plants 12/25/71 8/17/71
G Nitric Acid Plants 12/25/71 8/17/71
H Sulfuric Acid Plants 12/25/71 8/17/71
I Asphalt Concrete Plants 5/08/74 6/11/75
J Petroleum Refineries 5/08/74 6/11/75
K Storage Vessels for Petroleum Liquids 5/08/74 6/11/75
L Secondary Lead Smelters 5/08/74 6/11/75
M Brass and Bronze Production Plants 5/08/74 6/11/75
N Iron and Steel Plants 5/08/74 6/11/75
o Sewage Treatment Plants 5/08/74 6/11/75
P Primary Copper Smelters 1/15/76 10/16/74
Q. Primary Zinc Smelters 1/15/76 10/16/74
R Primary Lead Smelters 1/15/76 10/16/74
S Primary Aluminum Reduction Plants 1/26/76 10/25/74
TUVWX Phosphate Fertilizer Industry 8/06/75 10/22/74
Y Coal Preparation Plants 1/15/76 10/24/74
Z Ferroanoy Production Plants 5/04/76 10/21/74
AA Steel Plants: Electric Arc Furnaces 9/25/75 10/21/74
BB Kraft Pulp Mills 2/25/78 9/24/76
CC Glass Manufacturing Plants 6/15/79 10/07/80
DD Grain Elevators 8/05/78 1/05/77
EE Surface Coating of Metal Furniture 11/28/80 10/29/82
GG Gas Turbines 10/05/77 10/10/79
HH Lime Manufacturing Plants 5/07/78 5/05/77
MM Automobile and Light Duty Truck Surface Coating
Operations 10/05/79 12/24/80
PP Ammonium Sulfate Manufacturing 2/04/80 11/12/80
SS Industrial Surface Coating: Large Appliances 12/24/80 10/27/82
IT Metal Coil Surface Coating 1/05/81 11/01/82
26
-------
Chapter I-Environmental Protection Agency
~ 60.~ Determinallon of ron"itructlOn nr
modilication.
(al 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
construction (including reconstruc.
tion! or modification or the com-
mencement thereof within the mf'an-
ing of this part.
(b! The Administrator will respond
to any request for a determination
under paragraph (al of this section
within 30 days of receipt of such re-
Quest.
140 FR 58418. Dec. 16.19751
~ 60.6 Review uf plans.
(al When requested to do so by an
owner or operator. the Administrator
will review plans for construclion or
modification for the purpose of pro-
viding technical advice to the owner or
operator.
(b I( 1 I A sl'parale request shall be
submitted for I'ach constructIOn or
modification project.
(2) Each request shall identify thl'
location of such project. and be accom-
panied by technical information de-
sCribing thl' proposed nature. -IZI'.
desll{n. and ml't hod of operation oj
I'ach affected facility involved in such
project. including information on any
eQulpml'nt to be used for measure-
ment or control of emissions.
(I'I Neither a rl'Quest for plans
rl'Vll'W nor advIce furnished by the Ad-
ministrator in response to such re-
Quest shall (1 I rl'lieve an owner or op-
erator of legal responsibility for com-
pliance with any provision of this part
or of any appltcable State or local re-
QUirement. or (2) prevent the Adminis-
trator from implementing or enforcln~
any provision of this part or taKIn!!
any other actIOn authorized by the
Act.
136 FR 24877. Dec. 23. 1971. as amended Ot
39 FR 9314. Mar 8. 19741
~ 60.7 'utification and recurd keepin~.
(a) Any owner or operator subject to
the provisions of this part shall fur-
nish the Administrator written notifi-
cation as follows:
1 I) A notification of the date con-
struction '0r rf'construction as defined
under ~ 60.15> of an affected facility IS
commenced postmarked no latl'r than
30 days after such datI'. This require-
ment . shall not apply In the case of
mass-produced facilities which are
purchased in completed form.
(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 datf'.
13> A notification of the actual date
of initIal startup of an affected facility
postmarked within 15 days after such
~ 60.S - ~ 60.8
date.
14> A notification of any physical or
operational change to an eXIsting fa-
cility which may Increase the emiSSion
rate of any air pollutant to whIch a
standard appltes. unless that change is
specifically exempted under an appli-
cable subpart 0. in ~ 60.1411'1. This
notice shall be postmarked 60 days or
as soon as practicable before the
change is commenced and shall in-
clude informatIOn describing the pre-
cise nature of the change. present and
proposl'd emiSSion control systems.
productive capacity of the facility
bf'fore and after the change. and the
expectl'd compll'tlon date of the
change. The Administrator may re-
Quest additional rl'levant information
sUbsequent to this notice.
r 5) A notificatIOn oj the date upon
which demonstration of the continu-
ous mOnitoring system performance
commences In accordance with
~ 60.13<1'1. Notification shall bl' post-
marked not less than 30 days prior to
such date.
1 b> Any owner or operator subject to
the prO\'islons of this part shall main-
tain records of thf' occurrl'ncl' and du-
ration of any startup. shutdown. or
malfunction in the opl'ratlOn of an af-
lected facility; any malfunction of thl'
air POIiIHIOi1 control equipment: or
any periods dUrlnl{ which a continuous
mOnitoring system or monitoring
dence IS inoperatl\'l'
1 I' > Each 0\\ ner or operator required
to install a continuous monitoring
system shall submit a written report
of eXcl'ss emiSSIOns' as defined In ap.
plicable subparts> to the Administra-
tor for e\'l'ry calendar Quartl'r. All
Quarterly reports shall be postmarkl'd
by the 30th day lollowlng the end 01
each calendar Quarter and shall in-
clude the following Information:
< I) The magnitude of excess emis-
sions comp'Hed In accordance with
~ 60.13tra.
tor a copy of that notificatIon \\111 ,al.
Isfy the reqUIrements of paragraph, a J
of this sl'ction.
'Sl'(' 114. Clf'an Air Act a.s anwndt'd I L!
use 741~"
[36 FR :!1877. Dec 28. 1911 a~ ,1nH'ndt'd .'1
40 F'R ~625~ OCl 6. 1975. ~O F'R 5H~ lR n",.
16. 1975. 43 FR 8800. Mar. 3. 1978. ~5 FR
5617. Jan 23.19801
ti 60.~ Performancl' tesh.
(a> Within 60 days after acl1levlnR
the maximum productIOn rate at
which the affected facIlity will be op-
prated. but not later than 180 days
after InitIal startup of such facility
and at such other times as may be rl'-
Quired by the Administrator under SI'C-
tion 114 of the Act. the owner or oper-
ator of such facility shall conduct per-
formance testlSI and furnish the Ad.
mlnlstrator a wTltten report oj the re-
sults 01 such performance testl s J.
(b I 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 11) specifies
or approves. in specific cases. the use
of 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 results of which he has
determined to be adequate for indicat-
ing whether a specific source IS In
compliance. or (4) waives the require-
ment for performance tests becausl'
the owner or operator 01 a source has
demonstrated by other means tot ht'
AdmlnIstrator's satisfaction that I hl'
affected facility IS In compliance wlll1
the standard. Nothing in this para-
graph shall be construed to abrogate
the Admlnlstrator's authority to rl"
Quire testing undl'r sectIOn 1 H of the
Act.
II') Performance tests shall be con.
ducted under such conditIOns a:; tht'
AdminIstrator shall sppclfy 10 the
plant operator based on repn'" ntall\p
performance of the affectl.d la('II,I,
The owner or operator ,11all make
available to the AdminIstrator ,,)('h n',
-------
Chapter I-Environmental Protection Agency
cords as may be necessary to deter.
mme the conditions of the perform.
ance tests. Operations during periods
of startup. shutdown. and malfunction
shall not constitute representative
conditions for the purpose of a per.
formance test nor shall emissIons in
excess of the level of the applicable
emiSSion limit during periods of star.
tuP. shutdown. and malfunction be
considered a violation of the applica.
ble emission limit unless otherwise
specified in the applicable standard.
cd) The owner or operator of an af.
fected facility shall provide the Ad-
ministrator at least 30 days prior
notice of any performance test. except
as specified under other subparts. to
afford the Administrator the opportu.
nity to have an observer present.
(el The owner or operator of an af-
fected facility shall provide. or cause
to be provided. performance testing
facilities as follows:
(1) Sampling ports adequate for test
methods applicable to such facility.
(2) Safe sampling platform(s).
(3) Safe access to sampling
platCorm(s).
(4) Utilities for sampling and testing
equipment.
(f) Unless otherwise specified in the
applicable subpart. each performance
test shall consist of three separate
runs using the applicable test me~hod.
Each run shall be conducted for the
time and under the conditions speci.
fied m the applicable standard. For
the purpose of determinlnl compli.
ance with an applicable standard. the
arithmetic means of results of the
three runs shall applY. In the e\'ent
that a sample is accidentally lost or
conditions occur in which one of the
three runs must be discontinued be-
cause of forced shutdown. failure of
an irreplaceable portion of the sample
tram. extreme meteorological condi.
t Ions. or other circumstances. beyond
the owner or operator's control. com.
pliance may. upon the Administrator's
approval. be determmed usmg the
arithmetic mean of the results of the
two other runs.
'See 114. Clean Air Act as amended '42
U S.C. 7414»
[36 FR 24877. Dec. 23. 1971. as amended at
39 FR 9314. Mar. 8. 1974.42 FR 57126. Nov.
1. 1977: 43 FR 8800. Mar 3. 1978: 44 FR
336) ~ June 11. 1979]
.\vailabilit). of information.
availability to the public of in-
for tlon provided to. or otherwise
obta ed by. the Administrator under
t h \., ,'art shall be go\'erned by Part 2
of tillS chapter. (Information submit-
ted \'oluntarily to the Administrator
for the purposes of II 60.5 and 60.6 is
go. ..rned by ~ 2.201 through ~ 2.213 of
this chapter and not by ~ 2.301 of this
chapt..r. )
~ ~
f 60.8 - ~ 60.11
(Sec. I U. Clean Air Act as amended (42
U.S.C.7414»
[41 FR 36918. Sept. I. 1978. :>.s amended at
43 FR 8800. Mar. 3. 1978]
I 60.10 State authority.
The pro\'isions Of this part shall not
be construed in any manner to pre.
clude any State or political subdivision
thereof from:
(a) Adopting and enforcinl any
emission standard or limitation appli.
cable to an affected facility. provided
that such emission standard or limita.
tion is not less stringent than the
standard applicable to such facility.
(b) Requiring the owner or operator
of an affected facility to obtain per.
mlts. licenses. or approvals prior to ini.
tiating construction. modification. or
operation of such facility.
'Sec. 118. Clean Air Act as amended (42
U.S.C.7418))
[36 FR 24877. Dec. 23. 1971. as amended at
43 FR 8800. Mar. 3. 1978]
~ 60.11 Compliance with standards and
maintenance requirements.
(a) Compliance with standards in
this part. other than opacity stand.
ards. shall be determined only by per.
formance tests established by ~ 60.8,
unless otherwise specified in the appli-
cable standard.
(b) Compliance with opacity stand.
ards m this part shall be determined
by conducting observations in accord.
ance with Reference Method 9 in Ap-
pendix A of this part or any alterna-
tive method that is approved by the
Administrator. Opacity readings of
portions of plumes which contain con.
densed. uncombined water vapor shall
not be used for purposes of determin-
ing compliance with opacity standards.
The results of continuous monitoring
by transmlssometer which indicate
that the opacity at the time visual ob-
servations were made was not in
excess of the standard are probative
but not conclusive evidence of the
actual opacity of an emiSSIon. provided
that the source shall meet the burden
of proving that the instrument used
meets (at the time of the alleged viola.
tion) Performance Specification 1 in
Appendix B of this part, has been
properly maintained and (at the time
of the alleged violation) calibrated.
and that the resultinl data have not
been tampered with in any way.
(c) The opacity standards set forth
in this part shall apply at all times
except durinl periods of startup. shut-
down. malfunction. and as otherwise
provided in the applicable standard.
(d) At all times. includinl penods of
startup, shutdown. and malfunction.
owners and operators shall. to the
extent practicable. maintain and oper.
ate any affected facility including as.
sociated air pollution control equIp,
ment in a manner consistent with
28
nile 4O-Protedlon of Environment
good air pollution control practice for
mlnlml~nl emissions. Determination
of whether acceptable operating and
mamtenance procedures are being
uaed will be based on information
available to the Administrator which
may include, but is not limited to.
~onitorinl results. opacity observa.
tlons, review of operatinl and mainte.
nance procedures. and inspection of
the source.
le)(l) An owner or operator of an af.
fected facility may request the Admin-
istrator to determine opacity of emis-
sions from the affected facility during
the Initial performance tests reqUired
by ~ 60.8.
(2) Upon receipt from such owner or
operator of the written report of the
results of the performance tests reo
quired by ~ 60.8. the Administrator will
make a finding concerning compliance
with opacity and other applicable
standards. If the Administrator finds
that an affected facility is ':1 compli-
ance with all applicable standards for
which performance tests are conduct.
ed in accordance with ~ 60.8 of this
part but during the time such per-
formance tests are being conducted
fails to meet any applicable opacity
standard. he shall notify the owner or
operator and advise him that he may
petition the Administrator within 10
days of receipt of notification to make
appropriate adjustment to the opacity
standard for the affected facility.
(3) The Administrator will grant
such a petition upon a demonstration
by the owner or operator that the af-
fected facility and associated air pollu-
tion control equipment was operated
and maintained in a manner to mini.
mlze the opacity of emissions during
the performance tests; that the per-
formance tests were performed under
th.e .conditlons established by the Ad-
ml~lStrator; and that the affected fa-
cIlity and associated air pollution con-
trol equipment were incapable of
bemg adjusted or operated to meet the
applicable opacity standard.
(4) The Administrator will establish
an opacity standard for the affected
facility meeting the above requlre-
m.ents at a level at which the source
will be able. as indicated by the per-
formance and opacity tests. to meet
the opacity standard at all times
during which the source Is meeting
the mass or concentration emission
standard. The Adm1nlstrator will pro.
mulgate the new opacity standard In
the FEDERAL REGISTER.
(Sec. 114. Clean Air Act as amended (42
U.S.C.7414))
[38 FR 28565. Oct. 15. 1973. as amended at
39 FR 39873. Nov. 12. 1974: 42 FR 26206
May 23. 1977: 43 FR 8800. Mar. 3 1978' 45
FR 23379. Apr. 4. 1980) .. .
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Chapter I-Environmental Protection Agency
~ 60.12 Circumvention.
No owner or operator subject to the
provisions of this part shall build.
erect. install. or use any article. ma.
chine. equipment or process. the use of
which conceals an emission which
would otherwise constitute a violation
of an applicable standard. Such con.
cealment includes. but is not limited
to. the use of gaseous diluents to
achieve compliance with an opacity
standard or with a standard which IS
based on the concentration of a pollut-
ant in the gases discharged to the at.
mosphere.
[39 FR 9314. Mar. 8.1974)
~ 60.13 :vtoniloring requirement..
(a) For the purposes of this section.
all continuous monitoring systems reo
Quired under applicable subparts shall
be subject to the provisions of this sec.
tion upon promulgation of perform.
ance specifications for continuous
mOnitoring system under Appendix B
to this part. unless:
(1) The continuous mOnitoring
system IS subject to the provisIOns of
paragraphs (cH21 and (c)(3) of this
section. or
(2) otherwise specified In an applica.
ble subpart or by the Administrator.
(b) All continuous mOnitoring sys-
tems and monitoring devices shall be
installed and operational prior to con-
ducting performance tests under
~ 60.8. Verification of operatIOnal
status shall. as a minimum. consist of
the fOllowing:
(1) For continuous monitoring sys-
tems referenced in paragraph (C)( 1) of
this section. completion of the condl'
tioning period specified by applicable
requirements in Appendix B.
(2) For continuous mOnitoring sys.
terns referenced in paragraph (c)(2) of
this section. completion of seven days
of operation.
(3) For monitoring devices refer-
enced in applicable subparts. comple-
tion of the manufacturer's written re-
Quirements or recommendations for
checking the operation or calibration
of the device.
(c) During any performance tests reo
Quired under ~ 60.8 or within 30 days
thereafter and at such other times as
may be required by the Administrator
under section 114 of the Act. the
owner or operator of any affected fa-
cility shall conduct continuous moni-
toring system performance evaluations
and furnish the Administrator within
60 days thereof two or. upon request.
more copies of a written report of the
results of such tests. These continuous
monitoring system performance e\'alu-
ations shall be conducted in accord-
ance with the following specifications
and procedures:
(1) Continuous monitoring systems
listed within this paragraph except as
provided in paragraph (c)(2) of this
~ 60.12 - ~ 60.13
section shall be evaluated in accord-
ance with the reqUirements and proce-
dures contained in the applicable per.
formance specIficatIOn of Appendix B
as follows:
(i) Continuous mOnitoring systems
for measuring opacity of emiSSions
shall comply with Performance SpecI-
fication 1.
(ii) Continuous mOnitoring systems
for measuring nitrogen oxides emis-
sIOns shall comply with Performance
Specification 2.
riii> Continuous mOnitoring systems
for measuring sulfur dioxide emiSSions
shall comply with Performance Speci.
ficatlOn 2.
riv) Continuous mOnitoring systems
for measuring the oxygen content or
carbon dioxide content of effluent
gases shall comply with Performance
Specification 3.
(2) An owner or operator who. prior
to September 11. 1974. entered Into a
binding contractual obligation to pur.
chase specific continuous mOnitoring
system components except as refer-
enced by paragraph (c I( 2)( iii> of this
section shall comply with the follow-
Ing requirements:
ri) Continuous mOnitoring systems
for measuring opacity of emiSSions
shall be capable of measuring emission
levels wIthin '" 20 percent with a confi-
dence level of 95 percent. The Calibra-
tion Error Test and associated calcula.
tion procedures set forth in Perform.
ance Specification 1 of Appendix B
shall be used for demonstrating com-
pliance with this specification.
(ii) Continuous mOnitoring systems
for measurement of nitrogen oXides or
sulfur dioxide shall be capable of
measuring emission levels within :!: 20
percent with a confidence level of 95
percent. The Calibration Error Test,
the Field Test for Accura.cy < Relati\'e).
and associated operating and calcula-
tlon procedures set forth in Perform-
ance Specificatlon 2 of Appendix B
shall be used for demonstrating com-
pliance with this specification.
(iii) Owners or operators of all con.
tinuous mOnitoring systems installed
on an affected facility prior to October
6. 1975 are not required to conduct
tests under paragraphs (c)(2)(}) and/or
(ii> of this section unless requested by
the Administrator.
(3) All continuous monitoring sys-
tems referenced by paragraph < c H 2) of
this section shall be upgraded or reo
placed (if necessary) with new con-
tinuous mOnitoring systems, and the
new or Improved systems shall be dem-
onstrated to comply with applicable
performance specifications under
paragraph (c)( 1> of this section on or
before September 11, 1979.
(d) Owners or operators of all con-
tinuous monitoring systems installed
In accordance with the provisions of
this part shall check the zero and span
drift at least once dally in accordance
with the method prescribed by the
29
Title 40-Protection of Environment
manufacturer of such systems unless
the manufacturer recommends adjust.
ments at shorter intervals. in which
case such recommendations shall be
followed. The zero and span shall. as a
minimum. be adjusted whene\'er the
24-hour zero drift or 24-hour callbra.
tlon drift limits of the applicable per.
formance specifications in Appendix B
are exceeded. For continuous monnor.
Ing systems measuring opacny of emis.
sions. the optlcal surfaces exposed to
the effluent gases shall be cleaned
prior to performing the zero or span
drift adjustments except that for sys.
terns using automatic zero adjust.
ments, the optical surfaces shall be
cleaned when the cumulauve automat.
ic zero compensation exceeds four per.
cent opacity. Unless otherwise ap-
proved by the Administrator, (he fol-
lowing procedures. as applicable. shall
be followed:
(1) For extractive continuous moni-
toring systems measuring gases. mini.
mum procedures shall include In(ro-
ducing applicable zero and span gas
mixtures Into the measurement
system as near the probe as is practi.
caL Span and zero gases certified by
their manufacturer to be traceable to
National Bureau of Standards rplt-r.
ence gases shall be used whl'n('v('r
these reference gases are aV'\llable
The span and zero gas mixtures <;nall
be the same compositIOn as speci fled
in Appendix B of this part. Every SiX
months from date of manufacture.
span and zero gases shall be reana.
lyzed by conductlng triplicate analyses
with Reference Methods 6 for SO,. 7
for NO" and 3 for 0, and CO,. respec.
tively. The gases may be analyzed at
less frequent intervals if longer shelf
lives are guaranteed by the manufac-
turer.
(2) For non-extractive contilluous
monitoring systems measuring gases,
mmimum procedures shall Include
upscale check(sl using a certified call-
bration gas cell or test cell which IS
functionally eqUivalent to a known gas
concentration. The zero check may bf>
performed by computmg the zero
value from upscale measurements or
by mechanically producmg a zero con.
ditlOn.
(3) For continuous mOllltonnl( sys.
terns measuring opacity of emissions.
mmimum procedures shall Include a
method for producmg a simulated zero
opacity conditIOn and an upscale
(span) opacity condItion using a certi-
fied neutral density filter or other reo
lated techlllQue to produce a known
obscuration of the light beam. Such
procedures shall provide a system
check of the analyzer internal optical
surfaces and all electronic circuitry m.
cluding the lamp and photodetector
assembly.
(I'I Except for system breakdowns.
repairs. calibration checks. and zero
and span adjustments reqUired under
-------
Chapt.r I-Environm.ntal Prot.ction Ag.ncy
paragraph (d) of this section. all con.
tinuous monitormg systems shall be in'
contmuous operation and shall meet
minimum frequency of operation reo
qUlrements as follows:
< 1) All continuous mOnitoring sys-
tems referenced by paragraphs (c)
-------
Chapter I-Environmental Protection Agency
physical or operational change. All op.
erating parameters which may affect
emissions must be held constant to the
maximum feasible degree for all test
runs.
(C) The addition of an affected facili.
ty to a stationary source as an expan.
slon to that source or as a replacement
for an existing facility shall not by
itself bring within the applicability of
this part any other facility within that
source.
(d) [Reserved]
(e) The following shall not. by them-
se I ves. be considered modifications
under this part:
(1) Maintenance. repair. and replace-
ment which the Administrator deter-
mines to be routine for a source cate-
gory, subject to the provisions of para-
graph (C) of this section and ~ 60.15.
~ 60.14
(2) An increase in production rate of
an existing facility if that increase
can be accomplished without a capital
expenditure on that facility.
(3) An increase in the hours of oper-
atIon.
(4) Use of an alternative fuel or raw
material if. prior to the date any
standard under this part becomes ap-
plicable to t hat source type. as pro-
vIded by ~ 60.1. the existing facility
was designed to accommodate that al-
ternative use. A facility shall be con-
sidered to be designed to accommodate
an alternative fuel or raw material if
that use could be accomplished under
the facility's construction specifica.
tions as amended prior to the change.
Conversion to coal required for energy
considerations. as specified in section
111<(1)(8) of the Act. shall not be con-
sIdered a modification.
~H
Title 40-Protection of Environment
(5) The addition or use of any
system or device whose pnmary func-
tIOn is the reduction of air pollutants,
except when an emissIOn control
system is removed or is replaced by a
system which the Admintstrator deter-
mines to be less environment all\' bene.
ficial. .
(6) The relocation or change In own-
ership of an existing facility.
(f) Special provisions set forth under
an applicable subpart of this part shall
supersede any conflicting provIsions of
this section.
(g) Within 180 days of the comple-
tion of any physical or operational
change subject to the control mf'as.
ures specifIed in paragraph (a' of {his
section, compliance with all applicable
standards must be achieved.
(40 FR 58419. Dec. 16. 1975. amended at 43
FR 34347. Aug. 3,1978: 45 FR 5617. Jan ~3.
1980]
-------
Chapt.r I-Environm.ntal Prot.ction Ag.ncy
Subpart G-St.nd.rcI. of
Perform.nc. far Nitric Acid PI.n..
A 60.70 Applicability and d~.iJ11ation of
arr~ct~d facility.
(a) The provisions of this subpart
are applicable to each nitric acid pro.
duction unit. which Is the affected fa.
clllty.
(b) An~' facility under paragraph (a)
of this section that commences con-
struction or modification after August
17.1971. is subject to the requirements
of this subpart.
(Srcs. III and 301(a) of thr Clean Air Act.
sec. 4(11 of Pub. L. 91-604. 84 Stat. 1683. ~c.
2 01 Pub. L. 90-148. 81 Stat 504 (42 U.S.C.
1857c-6.18571(a)11
(42 FR 37936. July 25.1977]
A 60.71 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.
(a) "Nitric acid production Unit"
means any facility producing weak
nitric acid by either the pressure or at-
mospheric pressure process. .
(b) "Weak mtric acid" means aCId
which is 30 to 70 percent in strength.
A 60.12 Standard for nitrolt~n oxidr..
(a) On and after the date on which
the performance test required to be
conducted by t 60.8 is completed. no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any affected facility any gases which:
(11 Contain nitrogen oxides. ex-
pressed as NO.. in excess of l.S kg per
metnc ton of acid produced (3.0 Ib per
ton I. the production being expressed
as 100 percent nitric acid.
(2) Exhibit 10 percent opacity. or
greater.
[39 FR 20794. June 14. 1974. as amended at
40 FR 46258. Oct. 6. 19751
A 60.73 Emi..ion monitoring.
(a) A continuous monitoring system
for the measurement of nitrogen
oxides shall be installed. calibrated.
~ 60.70 - ~ 60.74
maintained. and operated by the
owner or operator. The pollutant ~as
used to prepare calibration p.s nux.
tures under paragraph 2.1. Perform-
ance Specification 2 and for calibra-
tion checks under t 60.13(d) to this
part. shall be nitrogen dioxide (NO.).
The span shall be set at 500 ppm of ni-
trogen dioxide. Reference Method 7
shall be used for conducting monitor-
ing system performance evaluations
under t 60.13(c).
(b) The owner or operator shall es-
tablish a conversion factor for the pur-
pose of converting monitoring data
into units of the applicable standard
-------
Chapter I-Environmental Protection Agency
Subpart H-Standard. of
Performance for Sulfuric Acid Plants
o 60.80 Applicability and designation of
affected facility.
(a) The provisions of this subpart
are applicable to each sulfuric acid
production unit. which is the affected
facility.
(b) Any facility under paragraph (a)
of this section that commences con.
struction or modification after August
17.1971. is subject to the requirements
of this subpart.
(Sees. 111 and 301(a) of the Clean Air Act;
sec. 4(a) of Pub. L. 91-604. 84 Stat. 1683; sec.
2 of Pub. L. 90-148. 81 Stat. 504 (42 U.S.C.
1857e-6. 1857g(a»)
[42 PH 37936. July 25. 1977)
o 60.81 Definitions.
As used in this subpart. all terms not
defined herein shall have the meamng
given them in the Act and in Subpart
A of this part.
(a) "Sulfuric acid production unit"
means any facility producmg sulfuric
acid by the contact process by burning
elemental sulfur. alkylation acid. hy.
drogen sulfide. organic sulfides and
mercaptans, or acid sludge. but does
not include facilities where conversion
to sulfuric acid is utilized primarily as
a means of preventing emIssions to the
atmosphere of sulfur dioxide or other
sulfur compounds.
(b) "Acid mist" means sulfuric aCid
mist, as measured by Method 8 of Ap-
pendix A to this part or an equivalent
or alternative method.
[36 PH 24877. Dec. 23. 1971. as amended at
39 FR 20794. June 14. 1974]
o 60.82 Standard for sulfur dioxide.
(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 cause to be
discharged into the atmosphere from
any affected facility any gases which
contain sulfur dioxide in excess of 2 kg
per metric ton of acid produced (4 Ib
per ton). the productIOn being ex-
pressed as 100 percent H.SO..
[39 PH 20794. June 14. 1974]
060.83 Standard for acid mist.
(a) On and after the date on which
the performance test required to be
conducted by t 60.8 is completed. no
owner or operator subject to the provi.
sions of this subpart shall cause to be
discharged into the atmosphere from
any affected facility any gases which;
~ 60.80 - ~ 60.85
(1) Contain acid mist, expressed as
H.SO.. in excess of 0.075 kg per metric
ton of acid produced (0.15 lb per ton).
the production being expressed as 100
percent H,SO..
(2) Exhibit 10 percent opacity. or
greater.
[39 PH 20794. June 14. J974. as amended at
40 FR 46258. Oct. 6.1975]
060.84 Emission monitoring.
(a) A continuous momtoring system
for the measurement of sulfur dioxide
shall be installed, calibrated. main-
tained, and operated by the owner or
operator. The pollutant gas used to
prepare calibration gas mixtures
under paragraph 2.1. Performance
Specification 2 and for calibration
checks under t 60.13( d). shall be sulfur
dioxide (SO,). Reference Method 8
shall be used for conducting momtor-
ing system performance evaluations
under ~ 60.13(c) except that only the
sulfur dioxide portion of the Method 8
results shall be used. The span shajJ
be set at 1000 ppm of sulfur dioxide.
(b) The owner or operator shall es-
tablish a converSIon [actor [or the pur.
pose o[ converting momtoring data
into units of the applicable standard
(kg/metric ton. Ib/short ton). The
conversion factor shajJ be determined.
as a minimum. three times daily by
measuring the concentration of sulfur
dioxide entering the converter usmg
suitable methods (e.g.. the Reich test.
National Air Pollution Control Admin-
Istration PublicatIon No. 999-AP-13)
and calculating the appropriate con-
version [actor for each eight. hour
period as follo\\'s:
CF= k[l.OOO -0.015r/r -sl
where:
CF =converslon factor (kg/metric ton per
ppm. Ib/short ton per ppm).
k =constanl derived (rom material bal-
ance. For determining CF In metric
uno"-. k = 0.0653. For determining CF
In English unIts. k=0.1306
r =0 percentage of sulfur dioxidf" by volume
enlerlOg the gas converter. Appropri-
ate corrections must be made (or air
injection plants subject to the Admin.
istrator's approval.
s :::. percentage of sulfur dloxlde by volume
In the emissions to the atmosphere de.
termlned by the continUOus mOnitor-
ing system required under paragraph
fa) oC thiS section.
(c) The owner or operator shall
record all conversIOn factors and
values under paragraph (b) of this sec-
tion from which they were computed
(1.1'.. CF. r. and s).
(d) [Reserved]
(e) For the purpose of reports under
~ 60.7(c). periods of excess emissions
33
Title 40-Protection of Environment
shall be all three-hour periods' or the
arithmetic average of three consecu-
tive one-hour periods) during which
the Integrated average sulfur dioxide
emiSSions exceed the applicable stand-
ards unaer ~ 60.82.
(Sec. 114. Clean Air Act a.s amended (42
U.SC.7414))
[39 FR 20794. June 14. 1974. as amended at
40 FR 46258. Oct. 6. 1975. 43 FR 8800. Mar.
3. 19781
~ 60.~5 Test methods and procedures.
(a) The reference methods m Appen-
dix A to this part. except as pronded
for m ~ 60.8(b). shall be used to deter-
mme compliance with the standards
prescribed In ~ ~ 60.82 and 60.83 as [01-
lows: .
(1) Method 8 for the concentratIOns
of SO. and aCid mist;
(2) Method 1 for sample and \'eloclty
traverses:
(3) Method 2 for velocity and \'olu.
metric flow rate; and
(4) Method 3 [or gas analysis.
(b) The moisture content can be con-
sidered to be zero. For Method 8 the
sampling time for each run shall be at
least 60 mmutes and the minimum
sample volume shall be 1.15 dscm (40.6
dscf) except that smaller sampling
times or sample volumes, when neces.
sitated by process variables or other
factors. may be approved by the Ad-
ministrator.
(C) Acid production rate. expressed
In metric tons per hour of 100 percent
H.SO.. shall be determined dUring
each testing period by suitable meth-
ods and shall be confirmed by a mate.
rial balance over the production
system.
(d) Acid mist and sulfur dioxide
emIssions, expressed in g/metric ton of
100 percent H.SO.. shall be deter-
mined by dividing the emission rate in
g/hr by the acid production rate. The
emission rate shall be determined by
the equation. g/hr=Q.-c. where
Q.=volumetric flow rate of the efflu-
ent in dscmlhr as determined In ac-
cordance with paragraph '3,)(3) o[ this
sectIOn, and c = aCid mist and SO. con-
centratIOns m g/dscm as determined
in accordance with paragraph (a Ii 1) of
thIs section.
(Sec. 114.. Clean Air Act as amendf>d f 42
U S.C. 7414»)
(39 PH 20794. June 14. 1974. as amended"
43 FR 8800. Mar. 3. 1978]
-------
Chapter I-Environmental Protedion Agency
Subpart P-Standards of P.rformanc.
for Primary Copp.r Sm.lt.,.
SOURCE: 41 FR 2338, Jan. 15. 1978. unless
uthrrw\se notre!.
t 60.160 Applicability and dHlrnation of
a((rdrd facility.
ea) The provisions of this subpart
are applicable to the following affect.
ed facilities In primary copper smelt-
ers: Dryer, roaster, smelting furnace,
and copper converter.
cb) Any facility under paragraph (a)
of this section that commences con-
struction or modification after Octo.
ber 16, 1974, is subject to the require-
menU of this subpart.
(Sros. 111 and 301.
160.163 Standard for lulfur dioxidr.
ca) On and after the date on which
the performance test required to be
conducted by t 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any roaster. smelting furnace. or
copper converter any gases which con.
tain sulfur dioxide in excess of 0.065
percent by volume, except as provided
In paragraphs (b) and (c) of this sec-
tion.
cb) Reverberatory smelting furnaces
shall be exempted from paragraph (a)
of this section during periods when
the total smelter charge at the pri-
mary copper smelter contains a high
level of volatile Impurities.
(c) A change In the .Ud com busted
34
Titl. 4O-Protodlon of Environmont
In a reverberatory smelting furnace
shall not be considered a modification
under thla part.
. 60.164 Standard for viliblr rmi..ion..
la) On and after the date on which
the performance test required to be
conducted by t 60.8 Is completed, no
owner or operator sUbject to the provl.
sions of this subpart shall cause to be
discharged Into the atmosphere from
any dryer any visible emissions which
exhibit greater than 20 percent opac-
~~ .
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Chapter I-Environmental Protection Agency
may be set at a sulfur dioxide concen-
tration of 0.15 percent by volume if
necessary to maintain the system
output between 20 percent and 90 per-
cent of full scale. Upon completion of
the continuous monitoring system per-
formance evaluation, the span of the
continuous monitoring system shall be
set at a sulfur dioxide concentration of
0.20 percent by volume.
(Ii) For the purpose of the continu-
ous monitoring system performance
evaluation required under ~ 60.13
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Chapter I-Enviranmental Protection Agency
Subpart Q-Standard. of Perform-
ance for Primary Zinc Smelters
SouRn 41 FR 2340. Jan. 15. 1916. unless
oth{"rwise noted.
~ 60.170 Applicabilit~ and desir:nation of
affected facilit~.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities m primary zinc smelters:
roaster and sintering machine.
(bl Any facility under paragraph (a)
of this section that commences con-
struction or modificatIOn after Octo-
ber 16. 1974. is subject to the require.
ments of this subpart.
(SpC's 111. 30HaJ. Clean Air Act. see 4caf of
Pub L 9t-604. 84 Stal 1683. see Z 01 Pub
L 90.148 81 SIal 504 142 V S.C 1851e-6.
185j~laJ))
(4~ FR 37931. Jul~' 25. 1917J
~ 6n.171 n~tinitltJn~
As used m this subpart. all terms not
defmed herein shall ha\'e the meaning
glnn them in the Act and in Subpart
A of this part.
For the purpose of the continuo
ous monitoring systen. performance
evaluation required under 160.13(c).
the reference method referred to
under the Field Test for Accuracy
(Relative) in Performance Specifica.
tion 2 of Appendix B to this part shall
be Reference Method 6. For the Der.
36
Title 4O-Pratection of Environment
formance evaluation. each concentra-
tion measurement shall be of I hour
duration. The pollutant gas used to
prepare the calibration gas mixtures
required under paragraph 2.1. Per-
formance Specification 2 of Appendix
B. and for calibration checks under
160.13(d), shall be sulfur dioxide.
(b) Two-hour average sulfur dioxide
concentrations shall be calculated and
recorded daily for the 12 consecutive
2-hour periods of each operating day.
Each 2-hour average shall be deter.
mined as the arithmetic mean of the
appropriate two contiguous 1-~our
average sulfur dioxide concentratIOns
provided by the continuous monitor.
ing system installed under paragraph
(a) of this section.
(c) For the purpose of reports re-
Quired under ~ 60.7(c). periods of
excess emissions that shall be reported
are defined as follows:
(1) Opacity. Any 6-minute period
during which the average opacity. as
measured by the continuous monitor-
ing system installed under paragraph
(a) of this section. exceeds the stand-
ard under 160.174(a).
(2) Sulfur dioxide. Any 2-hour
period. as described in paragraph (b)
of this section. during which the aver-
age emissions of sulfur dioxide. as
measured by the continuous monitor.
ing system installed under paragraph
(aJ of this section. exceeds the stand.
ard under 160.173.
(Sec. 114. Clean Air Act as amended (42
V.S.C.1414»)
[41 FR 2340. Jan. 15. 1916. as amended at 43
FR 8800. Mar. 3. 19781
~ 60.176 Te.t method. and procedure..
(a) The reference methods in Appen-
dix A to this part. except as pro\'ided
for m 160.8(b), shall be used to deter-
mine compliance with the standards
prescribed in 1160.172. 60.173 and
60.174 as follows:
(I) Method 5 for the concentration
of particulate matter and the associat-
ed moisture content.
(2 J Sulfur dioxide concentrations
shall be determined using the continu-
ous monitoring system installed m ac-
cordance with ~ 60.175(a). One 2-hour
a\'erage period shall constitute one
run.
(b) For Method 5. Method 1 shall be
used for selecting the sampling site
and the number of traverse points.
Method 2 for determining velocity and
volumetric flow rate and Method 3 for
determining the gas analysis. 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 times or
\'olumes. when necessitated by procE'SS
variables or other factors. may bl' ap.
proved by the Admmistrator.
(Sec. 114. Clean Air Act as amended (42
V.S C 74141)
[41 FR 2340. Jan 15. 1~16. a.. amendl'd at 4~
FR 8800. Mar 3. 1978J
-------
Chapter I-Environmental Protection Agency
Subpart R-Standards of Performance
for Primary Lead Smelters
SOURCE: 41 FR 2340. Jan 15. 1976. unless
othen\'lse noted.
~ 60.1~0 Applicabilil)' and designalion of
affected facilil)'.
lal The provisIOns of this subpart
are applicable to the following aff ecl-
ed facilities in primary lead smelters:
smtering machine. sintering machine
discharge end. blasl furnace. dross re-
verberatory furnace. electric smelting
fu~nace. and converter.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or Q1odification after Octo.
ber 16. 1974. is subject to the require.
ments of this subpart.
(Secs. Ill. 301(al. Clean Air ACI: sec. 4(al 01
Pub. L. 91-604. 84 Stal. 1683. sec. 2 01 Pub.
L 90-148. 81 Stal. 504 (42 U S.C. 1857c-6.
1857g(aiJ'
[42 FR 37937. July 25. 1977J
~ 60.1~1
Definition....
As used m thIS subpart. all terms nol
defined herem shall have the meaning
given them in th~ Act and in Subpart
A of this part.
"Dross revPrberaton- furnace"
means any furnace used 'for the re-
moy'al or refining of impuritIes from
lead bullion.
(g I "Electric smeltmg furnace"
means any furnace in whIch the heat
necessary for smeltmg of the lead sul-
fide ore concentrate charge is generat-
ed by' passing an electric current
through a portion of the molten mass
in the furnace.
(h) "Converter" means any vessel to
which lead concentrate or bullIon is
charged and refined.
ndt'rj (42
U.S.C 7414»)
[41 FR 2340. Jan 15. 1976. as amended at 43
FR 8800. Mar. 3. 1978]
~ 60.\~6 Test methods and procedurr,.
(al The reference methods 111 Appen-
dix A to this part. except as proVIded
for in 9 60.8(bl. shall be used to deter-
mme compliance with the standards
prescribed in H 60.182, 60.183 and
60.184 as follows:
(11 Method 5 for the concentration
of particulate matter and the associat-
ed mOisture content.
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Chapter I-Environmental Protection Agency
160.186
Tltl. 4O-Protection of Environment
'2) Sulfur dioxide concentrat:ons
shall be determined using the continu-
ous monitoring system Installed In ac-
cordance with 160.185(a). One 2.hour
average period shall constitute one
run.
t b) For Method 5. Method 1 shall be
used for selecting the sampling site
and the number of traverse points.
Method 2 for determining velocity and
volumetric flow rate and Method 3 for
determining the gas analysis. 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 times or
"olumes. when necessitated by process
variables or other factors. may be ap.
proved by the Administrator.
ISee 114. CI.an Air Act as amend.d 142
u.s.c. 7414 II
[41 f'R ~340. Jan. 15. 1976. as am.nd.d at 43
FR 8800. Mar. 3. 19781
38
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Chapter I-Environmental Protection Agency
METHOD 20-DETERMINATION OF NITRO-
GEN OXIDES. SULFUR DIOXIDE, AND
OXYGEN EMISSIONS FROM STATIONARY
GAS TURBINES
1. Apphcabtltty and Pnnctple
1.1 Applicabil1ty. This method IS applica-
ble for the determination of nitrogen oX1des
'NO,). sulfur dioxide 'SO,). and oxygen ,0,)
em(SSIOns from stationary gas turbmes. For
the NO, and 0, determinations, this method
tncludes: (1) measurement system desum Cri-
teria. (2) analyzer performance sp~clflca.
lions and performance test procedures; and
(3) procedures for emiSSion testing.
1.2 Prmc1pJe. A gas sample IS continuous-
ly extracted Irom the exhaust stream 01 a
stationary gas turbme: a portion of the
sample stream 15 conveyed to instrumental
analyzers for determination of NO. and 01
content. Durmg each NO. and 001 determi-
nation. a separate measurement of 801
emissIons 15 made. using Method 6. or It
equivalent. The 01 determination is used to
adjust the NO. and 801 concentraUons to a
reference condition.
2. De!intltons
2.1 Measurement System. The total
equipment required for the determmatlOn
of a gas concentration or a gas emrsslOn
rate. The system COnsiSts of the folloWIng
major subsystems:
2.1.1 Sample Interlace. That portion 01 a
system that IS used for one or more of the
following. sample aCQuisition. sample trans.
portatlOn. sample condltion.ng, or protec-
tion of the analyzers from the effects of the
stack emuent.
2.1.2 NO, Analyzer. That portion 01 the
system that senses NO. and generates an
output proportional to the gas concentra.
hon.
2 1.3
system
output
lion.
2.2 Span Value. The upper limit of a gas
concentration measurement range that IS
specified for affected source categories In
the applicable part of the regulations.
23 Calibration Gas A known concentra.
lion of :1 ga~ In an appropriate dlltwnt gas.
2.4 CalibratIOn Error. The difference be.
t Wt't>n 'he gas concf'ntrallon mdlcated by
thf' m~asurement system and the known
concentration of the calibration gas.
2.5 Zero Dnft. The dlrrerence In the
mt'asurement system output rE"adings before
and after a stated penod of operation
durtn~ which 110 unscheduled maintenance,
rt'palr, or adjustment took place and the
mput concentration at thE" tlme of the meas.
un'ml'nts was zero.
2.6 Cahbrallon Drift. The difference In
the mE"asurE"ment system output re-admgs
before and after a stated period of operation
durmg which 110 unscheduled mamtenance-.
repair, or adjustment took place- and the
Input at the LIme- of the med.Surements was
a high-level value.
2 7 Residence Time. The elapsed time
from the moment the gas sample enters the-
probe tiP to the moment the same gas
sample reaches the analyzer mlet.
2.8 Response Time. The amount of time
rt"QUlred (or t he continuous mOnitoring
~ystem to display on the data output 95 pl'r.
Cl'nt of a step change In pollutant conct'n-
tratlon-
01 Analyzer. That portion of the
that senses O~ and generates an
proportional to the gas concentra.
App.A
2.9 Interff>rf'ncf' Response The output
rf'sponse- of t he measurement system to a
component In the sample Io:'~. other than
the gas component being mea...;;urt>d.
3. l~It'a.surt'menl Sl)slem Per/ormancr
Spec1!1calwns
3.1 NO, to NO Con\'€'rter. Greater than
90 percent con\'erSlOn efficiency of NO, to
NO.
3.2 Interfe-rence Response. Lt'~ than = 2
percent of the span value-.
33 Reslde-nce Time. No gre-ater than 30
seconds.
3.4 Response Time No greater than 3
mmutes.
3.5 Zero Dntt Less than = 2 percE"nt of
the span value.
3.6 Calibration Dnft. Less than", 2 per-
cent of the span value.
4. Apparatus and Reagent.!
4.1 Measurement System. Use any mea-
surement system for NO. and 0, that IS ex.
pf"cted tc mee-t the specifications an this
method, A schematic of an acceptable mea-
surement system IS shown In Figure 20-1.
The essential compont-nts of the measure.
ment system are descnbed be-low'
~
,
\
CAl taRA T10N
GAS
4 1.1 Sample Probe Heated stainless
steel. or f'Qul\'alent. open.e-nded, straight
tube of sufficient length to traverse the
sample- pomts.
4.12 Sample Lme Heated ( .,.9S'C) stain-
less steel or Teflon tubmg to transporf the
sample gas to the sample conditioners and
analyzers.
4.1.3 Calibration Vain' Assembly. A
three-\\'a\' \al\t' assembl\' to dlre-ct the- zero
and calibration gases to" the sampJe condl'
tloners and to the anal\'ze-rs The- calibratIOn
\al\'f' assembly shall be capable of blockmg
the sample Ras tlo\!. and of Introducmg cali-
bration gases to the me-asurement system
when In the calibratIOn mode.
4.1.4 NO, to NO Converter. That portIOn
of the- system that converts the- OItro~en
dioxide (N01) In the- samplE' gas to mtrogen
OXIdE" (NO' Somt' analyzers art' designed to
measure NO. as NO, on a wet basis and can
bt' used without an NO, to NO con\'erter or
a mOisturt> remo\ al trap pro\'lded the
sample Ime to the analyze-r IS heated
39
Title 40-Protection 01 Environment
I ..,.95'C) to thp mlE"t of the analyzer. III addl'
tlon. an NO, to NO converter I~ not rWll'~
sary If the NO, portion of tht, exhausf ~tL... l!--
1e-5s than S percent of tht' total NO. {'onCf'fl
tratlon As a gUldelme. an NO: to NCJ can
ve-rter IS not necessary If the gas turbmt' If.
operale-d at 90 percent or mort' of pt'ak load
capacJt~ A conve-rter 1$ necessar,\ unJ~'r
lower load conditions.
4.1.5 MOisture Removal Trap. A rt'fTig.
e-rator-type conde-nser designed to contmu-
ousl\' remove condensate from the samplf'
gas 'The mOisture- removal trap IS no: necf's,
san for anal\'zers that can mea.surt NO,
concentratlo~ on a wet basis. tor th('~f' ana.
Iyzers, (a I heat the sample hne up to the
mlPt of thE' analyzers. (b) determme the
mOisturE" content usmg methods subject to
the appro\'al of the Adnunlstrator. and ICJ
correct the NO. and 0, concentratIOns to a
dn basis.
4.1.6 Particulate Filter. An in.stack or an
out-ol.stack glass Ilber !ilter, of the type
specihed In EPA Relerence Method 5. ho".
e-\'E"r, an out-of-stack filter ~s recomme-nded
when the stack gas temperature exceeds 250
to 300'C.
41.7 Sample- Pump. A nonreactl\'t. leak.
frt'e sample pump to pull the sample (:as
NITROGE N
OXIDES
ANAL V lER
/
I
/
/
EXCESS
SAMPLE TO VENT
through the system at a tlo\\ rate suffl(~ll:'nt
to mlmmlze transport delay. Tht' pump
shall be made tram stamless ste-el or ('oated
with Teflon or eQUlva)ent
4.1.8 Sample Gas Mamlold A sampl" ~a.'
manifold to dh'ert portIOns of the samplE'
~as stream to the- analyzers The mamfold
ma~ be constructed of glass. Teflon typr
316 stainless steel. or eQul\'alE"nt
4.1.9 Oxygen and Analyzer An anal\"'zer
to determInt' the percent 0, conce-nt ration
of the sample g~ stream.
4.1.10 Nitrogen OXides Analyzer An ana.
Ivzer to determme the ppm NO. conCl'ntra.
t'lOn In the sample gas stream
4 1.11 Data Output A stnp.char! record.
er, analog computer, or digital re-corder for
recordmg measurement data.
4.2 Sulfur Dioxide AnalysIs EPA Rder.
e-nce Method 6 apparatus and rea~ent~
4.3 NO. Caliberatlon Gases Th" callbra.
tlon gases (or the NO. analyze-r ma~ b{' NO
In N" NO, In air or N,. or NO and NO, In 1';,
For NO. measuremt'nl anaJyz~r" that rl
qUire oXidatIOn of NO to NO, r tll r allt;ra
-------
Chapt., I-Environmental Protection Agency
!Ion gases must be in the form of NO in N,.
Us£' (our calibration gas mixtures &S specI-
fied belo...:
4 3 I HIgh-level Gas. A gas concentratIon
that IS eqUivalent to 80 to 90 percent of the
span \'al ue
43 2 MId-level Gas A gas concentration
that 15 f"Qulvalent to 45 to 55 percent of thf'
spa.n valut'.
" J 3 Lov. -level Gas. A gas concentration
that" equIvalent to 20 to 30 percent or the
span val Ul'
" 3 ~ Zf'ro Gas A gas concentration of
II's,", than 0.25 pe-Teent of the span value
Ambl~nt air ma)' be used for thr NO. zero
g....
4 4 0, Calibration Gases. Use ambient alT
at 209 perct'nt as the high-level 0, ga:, Use
a g&.S concentration that is equIValent to 11-
14 percent 0, for the mid.level gas. Use pu.
rifled mtrogen for the zero gas
4.5 NO,/NO Gas MIxture For detennm.
tng the con\'erSlon eHlclenc)' of the NO, to
NO con\'f'rtf'r, us£> a calibration gas nuxtufl'
or NO, and NO in N.. The mixture will b..
knov.n concentrations of 40 to 60 ppm NO,
and 90 to 110 ppm NO and certifIed by the
gas manufacturer ThiS certification of gas
conct"ntrallon must Include' a brief descrlp,
tlon of tht> procedure follov..~d in detemun.
mg lhp concentrations,
5. M~a.suremcnt S1lstem Performance Test
Procedures
Perform th~ following procedures prior to
measurement of emissIOns (Sectton 6) and
only once for each test program, I.e., the
serlf"S of all test runs for a g)Yen gas turbtnf"
engme
5.1 Calibration Gas Checks. There are
tv.'o alternatives for checking the concentra.
tloru; of the calibration gases. (a) The fJrstls
to usp calibration gases that are docum~nt.
ed traceable to National Bureau or Stand.
ards Reference Materials. Usr Traceablhty
Protocol for £Jtabluhlng TT1tt Concentra.
lIon$ of Gcues VIed for Caltbrattons and
Audits ~f ConltnvolLS Source £m1l110n Mon.
Iton (Protocol N4mber 1) that IS a\'allablt.
from tht" En\'lronmental Monltormg and
Support Laboratory. Quality Assuranoe
Branch. MatI Drop 77. Ennronmental Pro'
t("ClIon ARenC)', Research Triangle Park,
North Carolina 27711. Obtain a certifIcation
from the gas manufacturrr that tht" proto.
col Yo as followed These calibration gases are
not to be analyz.ed with the Reference
Methods rat,on gas re.
sponses dors not predict the actual responsf'
or the 10" .Irvel (not applicable for Ihe 0,
analyZe" and hieh.level lases within :';2
pt'rcenl of the- span \'alue, tht' calibrahon
shall tw cOn5ldt"red In\'alld. Take corrrctn'f'
measurt's on thr measurement system
before proct"f"dml with the test.
40
5.4 Interference Response. Introduce the
gaseous components listed in Table 20-1
tnto the measurement system separately. or
as gas mixtures. Determine the total inter.
ferrnce output response 01 the system to
thele components tn concentratIOn units;
record thE' values on a form similar to
Fieure 20-4. If the sum of the interference
responses of the test gases for either the
NO. or O. analyZers IS greater than 2 per.
cent of the applicable span value. take cor
recUve meuure on the measurement
system.
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Chapter I-Environmental Protection Agency
Turbine type:
Date:
App.A
Identification number
Test number
Title 40-Protection of Environment
Analyzer type:
Identification number
Zero gas
Low. level gas
Mid. level gas
High. level gas
Cylinder
value,
ppm or %
Final analyzer
responses,
ppm or %
Difference:
initial-final,
ppm or %
I I I I I
SOO:!:50 ppm
i 200:!20 ppm
,
co.
,0.
Initial analyzer
response,
ppm or %
Percent draft =
Absolute difference
Span value
x 100.
co
so.
'0 = 1 percenl
20 9 ~ , percenl
Figure 20.3.
Zero and calibration data.
TABLE 20-1-INTERFERENCE TEST GAS CONCENTRATION
41
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Chapter I-Environmental Protection Agency
App. A
Title 4O-P,otection .f Environment
Date of test:
Analyzer type:
Test gas
type
Concentration. ppm
Serial No.
Analyzer output
response
% of span
% of span =
Analyzer output response
Instrument span
X 100.
Figure 20-4.
Conduct an tntf"rferf"ncp r('sponse lest of
t"8ch anab'zer pnor to Its initial use in the-
held Thereafter. recheck the measurement
system If changf"s are made In the instru-
mentallon that could alter the Interference
response. e.I., changes in the type> of gas de-
teClor.
In lieu of conductmg the Interre-rence reo
sponse test. Instrumenl vendor data. which
dt"monstrale that for thf" test gases of Table
20-1 the mterft"rence performance speclflca-
lion 15 not e~cef"ded. are acceptable.
5 5 Rt'"sidence and Response TIme
5 5.1 Calculat~ th~ rrsid~nc~ lime 01 thr
samplt" tnter(act" portion of the mt"asure.
rnl'nl system U.!'tnK \'olumt and pump flow
rate Informallon Allernall\tly, If the re-
sponse ume df'termmed as definf"d an See-
uon 5,5.2 tS less than 30 seconds. the calcu-
lauons art not nt"C"essary
5.5.2 To dett'rmme response lime. first
mtroduce zt"ro "as mto the system at the
c-allbratlon val\'(" unul all rroadings are
Interference response.
stable, then, sWitch to monitor the stack tof-
nu~nt until a stablr rrading can b~ ob-
tamed. Record the upscale response- lime.
Nrxt. introducr h,gh-Ievrl calibration gas
into the system. Once- the- system has stab.-
liud at thr high-I~vrl concentration. SWitch
to monitor the stack effluent and walt until
a stabl~ valu~ is rrachrd. Rrcord the downs-
cale rt"sponse lime. Repeat the procedure
three- times. A stable value 18 eqUivalent to a
chanllr 01 Ie.. than 1 p~rcrnt 01 span valu~
lor 30 seconds or less than 5 p~rcent 01 thr
measured a\'erage concentration for 2 min.
utes. Record t he responsE' time data on a
form similar to Figure 20-5. the readmgs of
the upscale or downscale reponse time. and
report the greater time as the "response
time" for the analyzer Conduct a response
tlmr trst prior to thr Initial lIeld us~ 01 th~
measurement system. and repeat if changes
are made m the measurement system.
42
-------
Chapter I-Environmental Protection Agency
App. A
Date of test
Analyzer type
SIN
Span gas concentration
Analyzer span settmg
Upscale
ppm
ppm
seconds
2
seconds
3
seconds
Average upscale response
Downscale
seconds
seconds
2
seconds
3
seconds
Average dovllnscale response
seconds
System response time = slower average time =
seconds.
Figure 20.5.
Response time
5.6 NO, NO Con\'E"Tsion Efficlenc) Intro-
duct;' to the system. at the calibratIOn \'al\'(>
asspmbly, thE" NOJ/NO gab mixture (Secllon
4 5) Rt>cord thE' response of the NO. analyz.
~r If thE" instrument rE"spons(' indicates less
than 90 percent NO. to NO converSion.
maJ..t' rorrt"rtlOns to the measuTt"ment
sysll'm and repeat thli' check. AlternatIvely.
t ht' NO, to NO con\'f"rter check described in
Title 40 Part 86 Ccrt,flcatlOn and Test Pro.
c('dllr{'~ for Heat'y-Duty Eng1nes fOT 1979
and Later Model Years may be used. Other
all!;"rnate procedures may be used with ap-
pro\'al of the Administrator
6 1.1 Selection of a Sampling Site. Select
a samplm~ sllf> as closE" as practical to the
exhaust of the turbme, Turbme geometry.
stack configuration, Internal baffhn~, and
POint of IntroduCllon of dilution air will
\'ary for different turbme designs Thus.
each of these factors must bE' gl\,en special
consideration In order to obtam a rl"pre-
sentatlVe sample Whenever possible. the
sampling site shall be located upstream of
the POint of introductIOn of dilutIOn air Into
the duct. Sample porL~ may be located
before or after the upturn elbo\\'. m order to
accommodate the configuratIOn of the turn-
ing vanes and baffles and to permit a com-
plet£>, unobstructed tra\'erse of the stack,
The samplf. ports shall not be located
within 5 feN or 2 diameters (whichever 1S
6 1 Prellminanes.
6. EmtSS10n Measu.rement Test Procedure
43
Title 40-Protection 0' Environment
lessJ of the gas discharge to atmo'JplH're
For supplementary-fired, combml-'d-cyclf>
plants. the sampling slte shall be located be-
tween the gas turbme and the bOlIt.>r The
dlameter of the sam pi£> ports shall bt' ~ufll.
clent to allow t'ntry of the sarnplt' prtJtH'
61.2 A pn'llInmary 0, Ira\'I'rs" I" mad,'
for tht' purpOM' of selt'ctll1K 10\1,' (), \:\1111'''''
Conduct this test at tht' turbllH' I'undltlun
t hat IS the lowest percentalitl' or pt':\k load
operallOn mcludt'd In the pro~rarn Follow
the procedurr below or a1tt.>rnal1\'t' procf'-
dures subject to the appro\'al oC tht' Admin
Istrator may be used.
6.1.21 Minimum Number of Pomts
Selrct a minimum number oC POints :\..'i fol.
lows: (1) eight. Cor slacks having cross-St'C.
lIonal areas less than 1,5 ml 4161 (t:): 42J
one sample POint for rach 0 2 m' 42 :.: ft: of
arras, for stack..s of 1.5 mJ to 100 m. (161-
107.6 ftl) In cross-sectIOnal area, and' 3) one
sample POint Cor each 0 4 m) (4.4 Ct~) of art'a,
Cor stacks greater than 10,0 m : (107,6 ft I) In
cross-seCllonal area, Note that for circular
ducts. the number of sample POints must be
a multiple of 4, and Cor rectanguJar ducts,
the number oC POints must be one of those
listed In Table 20-2: there tore. round oft the
number f)C POints (upward), when appropn.
ate.
6 1,2.2 Cross-sectional Layout and Loca-
tion of Tra\'erse POints, After the number of
traverse pOints Cor the preliminary O. sam.
pIing has been determined, use Method 1 to
located the tra\,prse POints.
6123 Preliminary 01 Measurement.
Whllr the gas turbine IS operatln~ ,1.t the
lowf'st percent oC peak load. conduct :\ prp.
I1mlnary 0: mt'~urement as follo\l,s POSI.
tlOn the prob£' :\t tl1l' fIrst tra\Pr'". p01n1
and begin :-.amplmt( The minimum "ampllng
time at pach POint ...hall be I mmu[,' DillS
the average system response tlm(> DI'[pr.
mine thr average steady.stat£> concentratIOn
oC 0) at each POint and record the data un
FIKure 20-6
6.1 2.4 SeleClion oC Emission T('~t Sam.
piing POints, Select the eight 'iamplmK
POints at which the lo....est 0: concenlrallon
u,cere obtained, Use these ~arnt' POint..., fur :111
the lest runs at the different turbin" load
conditions. More t han ~Ight POints may b(>
used, IC deslrrd.
TABLE 20-2 -CROSS-SECTIONAL LAYOUT FOR
RECTANGULAR STACKS
--~_._--
\4a!rt.
a~O...1
-------
-- --_.-----
~O 0' traverse pOInts
9
12
,.
20
25
30
3.
42
49
].3
',1
S,J
'5 . ~
~ , 5
. . 6
" , 6
7.7
----
-------
Chapter I-Environmental Protection Agency
App. A
Titla 4O-Protactlan af Envlranmant
Location: Date
Plant
City, State
Turbme Identification:
Manufacturer
Model, serial number
Sample point Oxygen concentration, ppm
Figure 20-6. Preliminary oxygen traverse.
6.2 NO, and O. Measurement. Thia test ia
to be conducted at each of the specified load
conditions. Three test runs at each load con-
dition constitute a complete test.
6.2.1 At the bertnnlnl of each NO. test
run and. as applicable. durin, the run,
record turbine data as indicated In Flrure
20-7. Also. record the location and number
of the traverse points on a dlacram.
6.2.2 PositIon the probe at the first point
determined In the preceding section and
belln aamplln,. The minimum aamplinl
time at each point shall be at leut I minute
plus the averare s;stem response time. De-
termine the aver&le steady-state concentra-
tion of O. and NO, at each point and record
the data on Flrure 20-8.
44
-------
Chapter I-Environmental Protection Agency
App. A
Title 40-Protedion 0' Environment
--
Test operator
TURBINE OPERATION RECORD
TurbIne IdentIfIcatIon.
Type
Senal No.
Location
Pldnt
City
AmbIent temperature
Ambient humIdIty
Test tIme start
r est tIme fonlsh
Fuel flow ratea
\/Vater or steam
Flow ratea
AmbIent Pressure
Date
UltImate fuel
AnalysIs C
H
o
N
S
Ash
H20
Trace Metals
Na
Va
K
etcb
OperatIng load
aDescribe measurement method, I.e., continuous flow meter,
start fonlsh volumes, etc.
bl.e , addItIonal elements added for smoke suppressIon.
FIgure 20.7
Stationary gas turbIne data.
T urlHl1e Hlentlflcatlon
M.tI\lltacturer
Model. sendl No.
lliLltion
Pl,ll1t
CIty. S.tdte
AllIlHcnt teT1\perdture
An11Hent ~ressure
[)oIte
If:\IIIIIW
\1.lfl ----
T e~t IlIlIe
Ionlsh
FIgure 20.8.
T es toper a tOl name
02 Instrument type
Serial No
NOx Instrument type
Serial No.
a
a
Sdmple Time, 02, NOx'
pOint min. % ppm
--
dAverdyt: ~U~d«ly :.ldl~ ..,.shH~ I"H" lI:f (lIdl:' 'It
Instrument readout
Stationary gas turbIne sample pOInt record
45
-------
Chapter I-Environmental Protection Agency
8.2 J Alter sampling the last POint. con.
elude the test run by recording the final
turbme operating para.rn~ters and by deter-
mining the zero and calibration drift. as fol-
iows
Immediately following the test run at
each load condition. or If adjustments are
necessary for the measurement system
dunng the tests. remtroduce the uro and
mld.le\'el calibration lues as described In
Sections 4 J. and 4.4. one at a time. to the
mea.sur~ment system at the calibration
\"al\'t" assembly. (Make no adjustments to
T he m~asurement system until after the
dnlt check.s are made) Record the analyz-
("f5' responses on a form similar to Figure
20-J If the drift values exceed the specified
limits. the test run preceding the check 15
consIdered invalid and ...111 be repeated fol-
lowing corrections to the measurement
system Alternatively, the test results may
be accepted provided the measurement
system 15 recaUbrated &nd the calibration
data '.hat result in thl!' hllhest cor~cted
emiSSion rate are used
6 3 SO. Measurement. This test IS con-
ducted only at the 100 percent peak load
condition Determine SO. uslnR' Method 6
App.A
or equivalent. durinl the test. Select a mini-
mum of SIX total POints from thoae required
for the NO. measurements; use two points
for each sample run. The sample time at
each point shall be at least 10 minutes.
Average the O. readings taken during the
NO, test runs at sample points cOn'espond.
ing to the SO, traverse points lSee Section
8.2.2) and use this average O. concentration
to correct the integrated SO. concentration
obtained by Method 6 to 15 percent O. (see
Equation 20- U.
If the applicable regulation allows fuel
sampling and analysIS for fuel sulfur con.
tent to demonstrate compliance with sulfur
emiSSion unit. emiSSion samplmg with Ref-
erence Method 6 IS not required. provided
the fuel sulfur content meets the limits of
the regulation.
7. Emu.non Calculal1on.s
7.1 Correction (0 15 Percent Oxygen.
USing Equation 20-1. calculate the NO. and
SO. concentrations (adJusttd to 15 percent
O,J The correction to 15 percent 0, is sensi-
tive to the accuracy of the O. measurement.
At the level of analyzer drift specified in the
method (=,=2 percent of full scale). the
46
Title 40-Protection of Environment
change In the O. concentration correction
can exceed 10 percent when the 0, content
o( the exhaust Is above 16 percent 0,.
Therefore 0, analyzer stability and careful
calibration are necessary.
C.cIJ . '.IS '
(hoot ton 20-1)
5.9
~FnZ-
Where:
C...3Pollutant concentration adjusted to
15 percent O. (ppm)
C_=Pollutant concentration measured.
dry basis (ppm)
5.9-20.9 percent 0.-15 percent 0.. the
deflned O. correction basis
Percent O. = Percent O. measured. dry
basis ("!oj
7.2 Calculate the average adjusted NO,
concentration by summmg the point values
and dividing by the number of sample
points.
I. Citahons
8.1 Curtis. F. A Method for Anal)'Zing
NO. Cylinder Gues-Speciflc Ion Electrode
Procedure. Monograph available from Emls.
slon Measurement Laboratory. ESED. Re-
search Triangle Park. N.C. 27711. October
1978.
-------
Section II
Selected Excerpts from the
Federal Register
Federal Register publications dealing with continuous source emission
monitoring: Promulgated Rules, Proposed Rules, and Announcements.
47
-------
'-
Ut
8m PART V:
.~ ENVIRONMENTAL
~ PROTECTION
~ AGENCY
e
.
MONDAY, OCTOBER &, 1975
.
REQUIREMENTS fOR
SUBMITTAL OF
IMPLEMENTATION
PLANS
STANDARDS FOR NEW
S1 A TIONARY SOURCES
Emission Monitoring
,
49
-------
~62~O
Title 4O--Protection of Environment
CHAPTER I-ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER c-AIR PROGRAMS
I FRL 423-6)
PART 51-REQUIREMENTS FOR THE
PREPARATION, ADOPTION AND SUB.
. MITTAL OF IMPLEMENTATION PLANS
Emission Monitoring of Stationary Sources
On September 11, 1974, the Environ-
mental Protection Agency IEPA) pro-
posed revisions to 40 CFR Part 51. Re-
qUirement.'; for the Preparation, Adop-
tion, and Submittal of Implementation
Plans. EPA proposed to expand ~ 51.19 to
require States to revise their State Im-
plementation Plans (SIP's) to include
legally enforceable procedures requiring
certam specified categories of existing
stationary sources to monitor emissions
on a continuous basis. Revised SIP's sub-
mitted by States in response to the pro-
posed revisions to 40 CFR 51.19 would
have' 1) required owners or operators
of specIfied categories of stationary
sources to Install emission morutoring
equipment within one year of plan ap-
proval. (2) specified the categories of
sources subject to the requirements, (3)
identified for each category of sources
the pollutant(s) which must be moni-
tored, '4) set forth performance specifi-
cations for continuous emission monitor-
ing instrument.';, (5) required that such
instrument.'; meet performance specifi-
cations through on-site testing by the
owner or operator, and (8) required that
data derived from such monitoring be
summarized and made available to the
State on a quart4!rty basis.
As a minimum, EPA proposed that
States must adopt and implemellt legallY
enforceable procedures to require moni-
toring of emissions for existing sources
In the fOllowing source categories (but
only for sources required to limit emis-
sions to comply with an adopted regula-
tion of the State Implementation Plan) :
(a) Coal-fired steam generators of
more than 250 million BTU per hour heat
Input 'opacity, sulfur dioxide, oxides of
nitrogen and oxygen);
1 b lOll-fired steam generators of more
than 250 million BTU per hour heat In-
put 'sulfur dioxide, oxides of nitrogen
and oxygen' . An opacity monitor was re-
qUired only if an emission control device
Is needed to meet particulate emission
regulations, or If violations of visible
emission regulations are noted;
(C) Nitric acid piants (oxides of
nitrog~n) ;
(d) .,ulfuric acid plant.'; (sulfur di-
oxide and
(e) ?troleum refineries' fiuid catalytic
crackin' unit catalyst regenerators
'opacit~' .
Simultaneously, the Agency proposed
sImilar continuous emission monitoring
requirement.'; for new sources for each of
the prevIOusly identified source categor-
ies. subject to the provisions of federal
New Source Performance Standards set
forth 10 40 CFR Part 60 Since many of
the technical aspect.'; of the two proposals
were slrrular. If not the same, the pro-
RULES AND REGULATIONS
posed regulations for Part 51 (i.e., those
relating to SIP's and existing sources)
included by reference many specific tech-
nical details set forth in 40 CFR Part 60,
(39 FR 32852).
At the time of the proposal of the con-
tinuous emission monitoring regulations
in the FEDERAL REGISTER, the Agency in-
vited comment.'; on the proposed rule-
making action. Many interested parties
submitted comment.';. Of the 76 comment.';
received, 35 were from electric. utility
companies, 26 were from oil refineries or
other industrial companies, 12 were from
governmental agencies, and 3 were from
manufacturers and 'or suppliers of emis-
sion monitors. No comments were re-
ceived from environmental groups. Fur-
ther, prior to the proposal of the regula-
tions in the FEDERAL REGISTER, the Agency
sought comment.'; from various State and
local air pollution control agencies and
instrument manufacturers. Copies of
each of these comments are available
for public inspection at the EPA Freedom
of Information Center, 401 M Street,
S.W., Washington, D.C. 20460. These
comments have been considered, addi-
tlonallnformatlon collected and assessed,
and where determined by the Adminis-
trator to be appropriate, revisions and
amendments have been made in for-
mulating these regulations promulgated
herein.
General Di.lcussion 01 Comments. In
general, the comments received by the
Agency tended to raise various objections
with specific portions of the regulations.
Some misinterpreted the proposed reg-
ulations, not realizing that emiS5ion
monitoring under the proPD6al was not
required unless a source was required to
comply with an adopted emission limita-
tion or sulfur in fuel limitation that was
part of an approved or promulgated State
Implementation Plan. Many questioned
the Agency's authority and the need to
require sources to use continuous emis-
sion monitors. Others stated that the
proposed regulations were infiationary,
and by theInselves could not reduce emis-
sions to the atmosphere nor could they
improve air Quality. A relatively common
comment was that the benefits to be de-
rived from the proPD6ed emi&sion moni-
torinr program were not commensurate
with the costs associated with the pur-
chase,lnstallation, and operation of such
monitors. Many stated that the proposed
regulations were not cost-elfectively ap-
plied and they objected to all sources
within an Identifted source category be-
Ing required to monitor emissions, with-
out regard for other considerations. For
instance, some suggested that It was un-
neceMary to monitor emissions from
steam generating plants that may soon
be retired from operation. or steam gen-
erating boilers that are infrequently used
(such as for peaking and cycling opera-
tions) or for those sources located in
areas of the nation which presently have
ambient concentrations better than na-
tional amb1imt air quality standards. This
latter comment was especiallY prevalent
in relation to the need for continuous
emission monitors designed to measure
emissions of oxides of nitrogen. Further,
commentors generally suggested that
state and local control agencies, rather
than EPA should be responsible for
determining which sources should moni-
tor emissions. In this reprd, the com-
mentors suggested that a determination
of the sources which should install con-
tinuous monitors should be made on a
case-by-case basis. Almost all objected to
the data reporting requirements stating
that the proposed requirement of sub-
miS5ion of all collected data was exceS5ive
and burdensome. Comments from state
and local air pollution control agencies in
general were similar to those from the
ut!l!ty and industrial groups, but in addi-
tion, some indicated that the manpower
needed to implement the prograIns re-
quired by the proposed regulations was
not available.
Rationale lor P:mission Monitoring
Regulation. Presently, the Agency's reg-
ulations setting forth the requirements
for approvable SIP's require States to
have legal authority to require owners
or operators of stationary sources to In-
stall, maintain, and use emission moni-
toring devices and to make periodic
reports of emission' data to the State
(40 CFR 51.11(a) (6». This requirement
was designed to partially Implement the
requirements of Sections 110(a) (2) (F)
(jj) and Oil> of the Clean Air Act, which
state that Implementation plans must
prOlVide "requirements for installation
of equipment by owners or operators of
stationary sources to monitor emissions
from such sources", and "for periodic
reports on the nature and amounts of
such emissions". However, the Original
implementation plan requirements did
not require SIP's to contain legally en-
forceable procedures mandating contin-
uous emiS5ion monitoring and recording.
At the time the original requirements
were published. the Agency had accumu-
lated little data on the availability and
rellab!1lty of continuous monitoring de-
vices. The Agency believed that the
state-of-the-art was such that it was
not prudent to require existing sources
toO install such devices.
Since that time, much work has been
aone by the Agency and others to field
test
-------
once per year, and in some cases, affected
sources probably have never been tested.
Manual stack tests are generally per-
formed under optlmwn operating con-
ditions. and as such, do not reflect the
full-time emission conditions from a
source. Emissions continually vary with
fuel firing rates, process material feed
rates and various other operating condi-
tions. Since manual stack_tests are only
conducted for a relatively short period
of time (e.g., one to three hours), they
cannot be representative of all operating
conditions. Further, frequent manual
stack tests (such as conducted on a
quarterly .or more frequent basis) are
costly and may be more expensive than
continuous monitors that provide much
more information. state Agency en-
forcement by field inspection Is also
sporadic, with only occasional Inspection
of certain sou"ces, mainly for visible
emiss"ton enforcement.
Continuous emission monitoring and
recording systems, on the other hand,
can provide a continuous record of emis-
sions under all operating conditions. The
continuous emission monitor is a good
indicator of whether a source is using
good operating and maintenance prac-
tices to minimize emissions to the at-
mosphere and can also provide a valu-
able record to indicate the performance
of a source In complying with appl1cable
emission control regulations. Addition-
ally, under certain Instances, the data
from continuous monitors may be suf-
ficient evidence to issue a notice of vio-
lation. The continuous emission record
can also be utllized to signal a plant
upset or equipment malfunction so that
the plant operator can take corrective
action to reduce emissions. Use of emis-
sion monitors can therefore provide val-
uable information to minimize emissions
to the atmosphere and to assure that
full-time control etrorts, such as good
maintenance and operating conditions,
are being ut1llzed by source operators.
The Agency believes that it Is necessary
to establish national minimwn require-
ments for emission monitors for specified
sources rather than allow States to de-
termine on a case-by-case basis the spe-
ciflc sources which need to continuously
monitor emissions. The categories speci-
fied In the regulations represent very sig-
nificant sources of emissioIUi to the at-
mosphere. States in developing SIP's
have generally adopted control regula-
tions to minimize emissions from these
sources, Where such regulations exist, the
Agency believes that continuous emission
monitors are necessary to provide infor-
mation that may be used to provide an
indication of source compl1ance. Further
it is bel1eved that if the selection ot
sources on a case-by-case basis were left
to the States, that some States would
probablY not undertake an adequate
emission monitoring prOgram. Some
State A-gencies who commented on the
proposed regulations questioned the
state-of-the-art of emission monitoring
and stated their opinion that the pro-
posed requirements were premature.
Therefore, it is the Administrator's
jUdgment that, in order to assure an
RULES AND REGULATIONS
adequate nationwide emission moni-
toring program, minimum emission mon-
itoring requirements must be established.
The source categories affected by the
regulations were selected because they
are significant sources of emissions and
because the Agency's work at the time of
the proposal of these regulations In the
field of continuous emission monJto,ring
evaluation focused almost exclusively on
these source categories. The Agency Is
continuing to develoP data on monJtoring
devic$ for additional source categories.
It is EPA's intent to expand the minimwn
continuous emission monitoring require-
ments from time to time when the eco-
nomic and technological feasib1llty of
continuous monitoring equipment is
demonstrated and where such monJtor-
Ing Is deemed appropriate for other sig-
nJficant source categories.
Discussion 01 Major Comments. Many
~I)mmentors discussed the various cost
aspects of the proposed regulatlops, spe-
cifically stating that the costs of con-
tinuous monitors were excessive and in-
fiationary. A total of 47 commentors ex-
pressed concern for the cost and/or cost
effectiveness of continuous monitors.
Further, the Agency's cost estimates for
purchasing and' Installing monitoring
systems and the costs for data reduction
and reporting were questlened. In many
cases, sources provided cost estimates for
installation and operation of continuous
monitors cOIUiiderably in excess of the
cost estimates provided by the Agency.
In response to these comments, a fur-
ther review was undertaken by the Agen-
cy to assess the cost impact of the regu-
lations. Three conclusions resulted from
this review. First, it was determined that
the cost ranges of the various emission
monitoring systems provided by the
Agency are generally accurate for new
sources. Discussions with equipment
manufacturers and suppl1ers confirmed
this cost information. Approximate in-
vestment costs, which include the cost
of the emission monitor, installation cost
at a new facllity, recorder, performance
testing, data reporting systems and asso-
ciated engineering costs are as follows:
for opacity, $20,000: for sulfur dioxide
and oxygen or oxides of nJtrogen and
oxygen, $30,000; and for a BOurce that
monitors opacity, oxides of nJtrogen, sul-
fur dioxide and oxygen, $55,000. Annual
operating costs, which include data re-
duction and report preparation, system
operation, maintenance, utilities, taxes,
insurance and annualized capital costs
at 10% for 8 years are:-$8,500; $16,000:
and $30,000 respectively for the cases
described above. <1 )
Secondly, the cost review indicated
that the cost of installation of emission
monitors for existing sources could be
considerably higher than for new sources
because of the difficulties in providing
access to a sampl1ng location that can
provide a representative sample of emis-
sions. The cost estimates provided by the
Agency in the proposal were specifically
developed for new sources whose in-
stallation costs are relatively stable since
provisions for monitorin~ equipment can
be incorporated at the time of plant de-
sign. This feature is not available for ex-
16211
isting sources, hence higher costs [:en-
erally result. *ctual costs of Installa oon
at existing sources may vary from one
to five times the cost of normal mstalla-
tion at new sources, and in some cast's-
even higher costs can result. For exam-
ple, discussions with Instrument suppll-
ers indicate that a tYPical cost of lI1,t:ll-
lation of an opacity mom tor on an l'Xlst-
ing source may be two to three timt's the
purchase price of the monitor. Difficul-
ties aiso exist for installation of gaseo~
monJtors at existing sources.
It should be noted that these Installa-
tion costs include material costs for scaf-
folding, ladders, sampling ports and
other items necessary to provide access
to a location where source emissions can
be measured, It is the Agency's opmlon
that such costs cannot be solely attrib-
uted to these continuous emission moni-
toring regulations. Access to sampling
locations is generally necessary to de-
termine compliance with applicable state
or local emission limitations by routine
manual stack testing methods. There-
fore. costs of providing access to a rep-
resentative sampling location are more
directly attributed to the cost of com-
pliance with adopted emission limita-
tions, than with these continuous emis-
sion monitoring regulations.
Lastiy, the review of cost information
indicated that a num~r of commentors
misinterpreted the extent of the pro-
posed regulations, thereby providing cost.
estimates for continuous monitors which
were not required. Specifically, all com-
mentors did not recognize that the pro-
posed regulations required emission mon-
itoring for a source only If an applicable
State or local emission limitation of an
approved SIP atrected such a source. For
example, If the approved SIP did not
contain an adopted control regulation to
limit oxides of nitrogen from st.eam-
generating, fossil fuel-fired boilers of a
capacity in excess of 250 million BTU per
hour heat'input. then such source need
not monitor oxides of nitrogen emis-
sions. Funher, some ut!\!ty industry com-
mentors included the costs of continuous
emission monitors for sulfur dioxide. The
proposed regulations, however, genPfally
allowed the use of fuel analysis by speci-
fied ASTM procedures as an alternative
which, in most cases. is less expensive
than continuous monJtoring. Finally. the
proposed 'regulations required the con-
tinuous monJtoring of oxygen in the
exhaust gaS only if the source must
otherwise continuously monitor oXides of
nJtrogen or sulfur dioxide. Oxygen in-
formation Is u~ed sOlely to provide a cor-
rection for excess air when convt'rting
the measurements of gaseous pollutants
concentrations in the exhaust gas stream
to units of an applicable emission limi-
tation. Some commentors did not recoi<'-
nize thi~ point (which was not specifical-
ly stated in the proposed regUlatlOnSJ
and provided cost estimates for oxygen
monitors when thev were not reqUlred- hy
the proposed regulations.
While not all commentors' cost esti-
mates were correct. for various reasons
noted above. It is clear that the rosts
associated with implementing these
emission monitoring regulations art' slg-
FEDERAL REGISTER, VOL. 40, NO. 194-MONDAV, OCTOln 6, 1975
51
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~fi2-t2
ruficant. The Administrator. however,
believes that the beneflts.to be derived
from emISSion monitormg are such that
the costs are not unreasonable. The Ad-
ministrator does, however, agree with
many commentors that the proposed reg-
ulations, In some cases, were not applied
cost-effectively and. as such. the regula-
tIons promulgated herein have been
modified to provide exemptions to cer-
tam sources from these minimum re-
quirements.
One comment from another Federal
Agency concerned the time period that
emissions are to be averaged when re-
porting excess emissions. Specifically. the
commentor assumed that the emission
control regulations that have been
adopted by State and local agencies were
.:enerally dl!signed to attam annual am-
bient air quality standards. As such, the
commentor pointed out that short-term
emission levels in excess of the adopted
emISSion standard should be acceptable
for reasonable periods of time.
The Administrator does not agree with
this rationale for the following reasons.
First. it is not universally true that an-
nual ambient standards were the design
basIs of emission control regulations. In
many cases. reauctions to attain short-
term standards requlre more control
than do annual standards. Even If the
regulations were based upon annual
standards. allowing excess emissions of
the adopted emission control regulation
on a short-term basis could cause non-
compliance with annual standards. More
importantly. however, a policy o( legally
aliowing excesses of adopted control reg-
ulations would in effect make the current
emission limitation unenforceable. If the
suggestion were implemented, a question
would arise as to what Is the maximum
emission level that would not be consid-
ered an excess to the adopted regulation.
TIle purpose of the adopted emission lim-
1 ta tlOn was to establish the. acceptable
emISSion level. Allowing emissions in ex-
cess of that adopted level would cause
confusion, ambiguity. and in many cases
could result in an unenforceable situa-
tion Hence the Administrator does not
concur with the commentor's suggestion.
ModiJlcations to the PrOfJosed Regu-
lations The modification to the regu-
latIOns which has the most signiftcant
Impact involves the monitoring require-
mer, ts for oxides of nitrogen at fossil
fuel-fired steam generating boilers and
at r.itric acid plants. Many commentors
correctly noted that the Agency in the
past (June 8.1973,38 FR 15174) had in-
dicated that the need for many emis-
sion control regulations for oxides of
nitr' ;:en were based upon erroneous
dat Such a statement was made after
a a 1iled laboratory analysis of the ref-
ereL , ambient measurement method
for n '.rogen dioxide revealed the method
to "lve false measurements. The
sampling technique generally indicated
concentrations of nitrogen dioxide
higher than actually existed in the
~tmosphere. Since many control agen-
"Ies pnor to that announcement had
adopted emiSSion regulations that were
determined to be needed based upon
RULES AND REGULATIONS
these erroneous data, and since new data,
collected by other measurement tech-
, niques, indicated ~t in most areas of
the nation such control regulations were
not necessary to satisfy the requirements
of the SIP, the Agency suggested that
States con.s1der the withdrawal of
adopted control regulations for the con-
trol of oxides of nitrogen from their SIP's
(May 8, 1974. 39 FR 16344). In many
States, control agencies have not taken
action to remove these regulations from
the SIP. Hence, the commentors pointed
out that the proposed regulations to re-
quire continuous emission monitors on
sources affected by such regulations Is
generally unnecessary.
Because of the unique situation in-
volving oxides of nitrogen control regu-
lations. the Administrator has deter-
minea that the proposed regulations to
continuously monitor oxides of nitrogen
emissions may place an undue burden on
source operators, at least from a stand-
point of EPA specifying minimum moni-
toring requlrements. The continuous
emission monitoring requlrements for
such sources therefore have been modi-
fied. The final regulations require the
continuous emission monitaring of
oxides of nitrogen onlY' for those sources
in Air Quality Control Regions (AQCR's)
where the Administrator has specifically
determined that a control strategy for.
nitrogen dioxide is necessary" At the
present time such control strategies are
required only for the Metropolitan Los
Angeles Intrastate and the Metropoli-
tan Chicago Interstate AQCR's.
It should be noted that a reeent com-
pilation of valid nitrogen dioxide air
quality data suggests that approximately
14 of the other 245 AQCR's in the nation
may need to develop a control strategy
for nitrogen dioxide. These AQCR's are.
presently being evaluated by the Agency.
If any additional AQCR's are Identified
as needing a control stratl:SY for nitro-
gen dioxide at that time. or any time
sUbsequent to this promulgation. then
States In which those AQCR's are lo-
cated must also revise their SIP's to
require continuous emission monitoring
for oxides of nitrogen for specified
sources. Further, It should be noted that
the regulations promulgated today are
minimum requirements, so that States,
If they believe the control of oxides of
nitrogen from sources Is necessary may.
as they deem appropriate, expand the
continuous emission monitoring require-
ments to apply to additional sources not
affected by these minimum requlrements.
Other modiftcations to the proposed
regulation resulted from various com-
ments. A number of commentors noted
that the proposed regulations included
some sources whose emission impact on
air quality was relati~el.v minor. Specifi-
cally. they noted that fossil fuel-fired
steam generating units that were used
solely for peaking and cycling purposes
should be exempt from the proposed reg-
ulations. Similarly, some suggested that
smalier sized units, particularly steam-
generating units less than 2,500 million
BTU per hour heat input. should also
be exempted. Others POinted out that
units soon to be retired from opera.tlon
should not be required to inStal1 con-
tinuous monitoring devices and that
sources located in areas of the nation
that already have air quality better than
the national standards should be relieved
of the required monitoring and reporting
requirements. The Agency has considered
these comments and has made the fol-
lowing judgments.
In relation to fossil fuel-fired steam
generating units, the Agency.has deter-
mined that sur.h units that have an an-
nual boiler capacity factor of 30% or less
as currently defined by the Federal Power
Commission shall be exempt from the
minimum requirements for monitormg
and reporting, Industrial boilers used at
less than 30% of their annual capacity.
upon demonstration to the State, may
also, be granted an exemption from these
monitoring requirements. The rationale
for this exemption Is based upon the fact
that all generating units do not produce
power at their full capacity at al1 times.
There are three major classifications of
power plants based on the degree to
which their rated capacity is utilized on
an annual basis. Baseload units are de-
signed to run at near full capacIty almost
continuously. Peaking units are operated
to supply electricity during periods of
maximum system demand. Units which
are operated for intermediate service
between the extremes of baseload and
peaking are termed cycling units.
Generally accepted definitions term
units generating 60 percent or more of
their annual capacity as baseload, those
generating less than 20 percent as peak-
ing and those between 20 and 60 percent
as cycling. In general. peaking units are
older, smal1er, of lower emciency. and
more costlY to operate than base load or
cycling units, Cycling units are also gen-
erally older, smal1er and less emcient
Than base load units. Since the expected
life of peaking units is relativelY short
and total emissions from such units are
smal1, the benefits gained by installing
monitoring instruments are small in
comparison to the cost of such equip-
ment. For cycling units, the question of
cost-effectiveness is more difficult to as-
certain. The units at the upper end of
the capacil¥ factor range (I.e.. near 60%
boiler capacity factor) are candidates for
continuous emission monitoring while
untts at the lower end of the range Ii.e..
near 20% boiler capacity factor! do not
represent good choices for continuous
monitors. Based upon available emission
Information, it has been calculated that
fossil fuel-fired steam generating plants
with a 30% or less annual boiler capacity
factor contribute approximately less
than 5% of the total sulfur dioxide from
al1 such power plants. (2) Hence, the
final regulations do not affect any bOIler
that has an annual boiler capacity factor
of less than 30%. Monitoring require-
ments will thus be more cost effectively
applied to the newer, larger, and more
emclent units that burn a relatively
lar~er portion of the total fuel supply.
Some commentors noted that the a~e
of the facility should be considered in
relation to whether a source need com-
fEDERAL REGISTER, VOL. 40, NO. 194--MONOAY, OCTOIER 6. 1975
52
-------
RULES AND REGULATIONS
ply with the proposed regulations. For the size Um1tatlon for boUers in relation
fossil fuel-fired steam generating units. to opacity Is warranted. The rationale
the exemption relating to the annual for this judgment is that the smaller-
boiler capacity factor previously dIs- sized units affected by the proposed reg-
cussed should generally. provide relief for ulatlon tend to be less efflclently oper-
older units. It Is appropriate, however, ated or controlled for particulate matter
that the age of the facility be consld- than are the larger-sized units. In fact.
ered for other categories of sources at- smaller units generally tend to emit more
fected by the proposed regulations. As particulate emissions on an equivalent
such, the final regulations allow that any fuel basis than larger-sized units. (2)
source that Is scheduled to be retired Because of the potential of opacity regu-
within five yearS of the inclusion of mon- latlon violations, no modifications have
ltorlng requirements for the source In been made to the regulations as to the
Appendix P need not c9IIIPly with the size of steam generating boilers that
minimum emission monitoring require- must measure opacity.
ments promulgated herein. In the Ad- Emissions of oxides of nitrogen from
minlstrator's judgment, the selection of boilers are a function of the temperature
five years as the allowable period for. in the combustion chamber and the cool-
this exemption provtdes reasonable re- ing of the combustion products. Em1s-
lief for th06e units that win shortly be siens vary considerably with the size and
retired. However. It maintains full re- the type of unit. In general, the larger
quirements on many older units with a units produce more oxides of nitrogen
number of years of service remaln1ng. emissions. The Agency therefore finds
In general, older units opera.te less e1!l.- that the mintmum size of a unit affected
clently and are less well controlled than . by the final regulations can be Increased
newer units so that emission monitoring from 250 to 1.000 million B'I'U per hour
Is generally useful. The exemption prCk heat Input, without significantly reduc-
vided in the final regulations effectively Ing the total emissions of oxides of nitro-
allows such retirees slightly more than a gen that would be affected by monitoring
two-year period of relief, since the sched- and reporting requirements. Such a mod-
ule of implementation of the regulations lficatlon would have the effect of exempt-
would generally require the installation ing approxlmately'58% of the boUers
of emission monitors by early 1978. over 250 million B'I'U per hour heat Input
States must submit, for EPA approvaJ, capacity, on a national basis, whUe main-
the procedures they will Implement to taining emission monitoring and report-
use this provision. States are advised ing requirements for apprmtimately 78%
that such exemptions should only be pro- of the potential oxides of nitrogen emis-
vided where a bona fide Intent to cease slons from such sources.(2) Further, In
operations has been clearly established. the 2 AQCR's where the Administrator
In cases where such sources postpone has specifically called for a control
retirement, States shall have established strategy for nitrogen dioxide. the boilers
procedures to require such sources to affected by the regulation constitute 50%
monitor and report emissions. In this re- of the steam generators greater than 250
gard, It should be noted that Section million B'I'U per hour heat input, yet
113(c) (2) of the Act provides that a.hy they emit 80% of the nitrogen oxides
person who falsifies or misrepresents a from such steftm generators In these
record, report or other document filed or 2 AQCR's.(2)
required under the Act shall, upon con- Also, certain types of boUers or burn-
victlon, be' subject to fine or Imprlson- ers, due to their design characteristlcs~
ment. or both. may on a regular basis attain emission
A further modification to the proP06ed levels of oxides of nitrogen well below
regulations affects the minimum s~ of the emission IImltatiods of the applies-
the units within each of the source cate- ble plan. The regulations have been re-
gOries to which emission monitoring and vised to allow exemption from the
reporting shall be required. As sUggested requirements for installing emission
by many conunentors. the Agency has in- monitoring and recording equipment for
vestigated the cost effectiveness of re- oxides of nitrogen when a facility Is
quiring all units within the identified shown during performance tests to or>-
source categories to install emission mon- erate with oxides of nitrosen emission
ltors. Each pollutant for each source levels 30% or more below the emission
category IdentUlpd In the proposed reg- limitation of the applicable plan. It
ulatlons waS evaluated. For fossil fuel- should be noted that this provision ap-
nred steam generating units, the pro- plies solely to oxides of nitrogen emls-
posal required compliance for all boilers sions rather than other pollutant emls-
with 250 million B'I'U per hour heat in- slons, since oxides of nitrogen emissions
put, or greater. For opacity. the proposed are more directly related to boiler de-
regulations required emission monitoring sign characteristics than are other
for all coal-fired units, whUe only those pollutants.
oil-fired units that had been observed as Similar evaluations were made for
violators of visibl~ emission regujations nitric acid plants. sulfuric acid plants
or must use an emISSion control device to and catalytic cracking unit catalyst re-
meet partlcul~te matter regulations were generators at petroleum refineries. For
required to Install such devices. Gas- each of these Industries It was found that
fired units were exempted by the pro- modJ1lcations to the proposed regulations
posed regulations. could be made to increase the minimum
After Investigating the particulate size of the units affected by the proposed
emission potential of these sources, it has regulations without significantly de-
been deterrruned that no modification in creasing the total emissions of various
162-t~
pollutant..~ that would be alYected bv
these monitoring and reporting reqUIre-
ments. Specifically. for nitric acid plants
it was found that by modifying the pro-
posed regulations to alYect onlv those
plants that have a. total daily productIOn
capacity of 300 tons or more of nitnc aCid
(rather than affecting all facill ties as
proposed) that approximately 79"'r of
the nitric acid production on a national
basis would be affected by the provisions
of these monitoring and reporting re-
quirements. On the other hand. such a
modification reduces the number of
monitors required for compliance with
these regulations by approximately 4Ji"'c.
(2) At the present time, only nitric acid
plants In AQCR's where the Administra-
tor has specifically called for a control
strategy for nitrogen dioxide will be can-
didates for continuous emisSion monitor-
ing requirements for the reasons men-
tioned previously. In the 2 AQCR's where
such a control strategy has been called
for, there is only one known nitric acid
plant and that is reported to be less than
300 tons per day production capacity-
hence no nitric acid plants at the present
time will be affected by these momtorlng
requirements.
Similarly, evaluations of sulfuric acid
plants and catalytic cracking catalyst re-
generators at petroleum refineries re-
sulted in the conclusion that mmimum
size limitations of 300 tons per day pro-
duction rate at sulfuric acid plants. and
20,000 barrels per day of fresh feed to
any catalytic cracking unit at petroleum
refineries could be reasonably estab-
lished. Such modifications exempt ap-
proximately 37% and 39% respectively
of such plants on a national basis from
these emission monitoring and reporting
requirements. while allowing about 9%
of the sulfur dioxide emissions from sul-
furic acid plants and 12% of the par-
ticulate matter emissions from catalytic
cracking units to be emitted to the at-
mosphere without being measured and
reported. (2) The Agency believe that
such modifications provide a reasonable
balance between the C06ts associated
with emission monitoring and reporting,
and the need to obtain such information.
A number of commentors suggested
that sources be exempt from the pro-
posed emission mOnitoring regulations if
ouch sources are located within areas of
the nation that are already attaining
national standards. The Administrator
does not believe that such an approach
would be consistent with Section 110 of
the Clean Air Act, which reqUIres con-
tinued maintenance of ambient stand-
ards after attainment. In many areas.
the standards are being attained only
through effective implementatIOn of
emission limitations. Under the Clean Air
Act. continued compliance with emis-
sion !Imitations in these areas is Just as
important as compliance in areas which
have not attained the standards.
Another major comment concerned
the proposed data reporting require-
ments. Thirty-four '34) commentors ex-
pressed concern at the amount of data
which the proposed regulatIOns r"Qlured
to be recorded. summarized. and SIJbmlt-
FEDEIAL IEGISTEI. VOL. 40. NO. 194-MONDAY. OCTOSEI 6. 1975
53
-------
t62-l-t
ted to the State. It was generally indi-
cated by the commentors that the data
reportmg requirements were excessive.
Commentors QuestIOned the purpose of
reportmg all measured data while some
State aKencies mdicated they have lim-
ited resources to handle such informa-
tion. EPA believes that, in some cases.
the commentors misconstrued the data
reporting reoUirements for existing
sources. In light of each of these com-
ments, the final regulations. with respect
to the data reporting requirements for
gaseous pollut;mts and opacity, have
been modified.
For gaseous emissions-, the proposed
regula tions required the reporting of all
one-hour averages obtained by the 'emis-
sion monitor. Because of the comments
on this provision. the Agency has reex-
amined the proposed data reporting re-
Quirements. As a result. the Agency has
detennined that only information con-
"ernmg emissions in excess of emission
limitations of the applicable plan Is nec-
essary to satisfy the intent of these reg-
ulatIOns. Therefore. the data reporting
reQwrements for gaseous pollutants
have been modified. The final regulations
require that States adopt procedures that
would require sources to report to the
State on emission levels in excess of the
applicable eInis~lon lImitaUons (I.e.. ex-
cess emissions I for the time period spec-
ified m the regulation with which com-
pliance is determined. In other words. If
an applicable emission limitation re-
qUired no more than 1.0 pounds per hour
SO to be emitted for any two-hour aver-
agmg perrod. the data to be reported by
the source should Identify the emission
level' i.e., emISsions stated in pounds per
hour) averaged over a two-hour time
period. for' periods only when this emis-
sIOn level was in excess of the 1.0 pounds
per hour emission limitation. Further.
~ources shall be required to m:untam a
record of all continuous momtormg ob-
sen'atlons for gaseous pollutants' and
opacity measurements) for a period of
two veal's and to make such data avail-
able'to the State upon request. The final
regulations have also been amended to
add a provision to require source~ to re-
. port to the State on the apparent reason
for all noted violations of applicable reg-
ulatIOns.
The proposed data reporting require-
ments for opacity have also been modl-
tied Upon reconsideration of the extent
of the da ta needed to satisfy the infn1t
of the~c regulations. it is the Adminis-
trator's Judgment that for opacity States
must obtam excess emiSSIOn measure-
mero" during each hour of operation.
Ho\, \"er, before determimng excess
eml 'ms. the number of minutes gen-
eral exempted by State opacity regu-
JatlO. should be considered For ex-
ampie where a regulation allows two
m:m.tes of opacity measurements in
exce~s of the standard. the State
neNi onlv reqUire the source to re-
port all opacity measurements in excess
"r the standard during anyone hour.
mlnns th!' two-minute exemption. The
ex('css measurements shall be reported
m actual per cent opacitv averaged for
RULES AND REGULATIONS
one clock minute or such other time pe-
riod deemed appropriate by the State.
Averages may be calculated either by
arithmetically averaging a minimum of
4 equally spaced data points per minute
or by integration of the monitor output.
Some commentors raised Questions
concerning the provisions in the proposed
regulations -which allow the use of fuel
analysis for computing emissions of aul-
fur dioxide in lieu of installing a con-
tinuous monitoring device for this pol-
lutant. Of primary concern with the fuel
analysis approach among the com-
mentors was the frequency of the analy-
sis to determine the sulfur content of the
fuel. However, upon inspection of the
comments by the Agency. a lJIore sig-
nificant issue has been uncovered. The
Issue involves the determination of what
constitutes excess emissions when a fuel
analysis Is used as the method to measure
source emissions. For example. the sulfur
content varies significanUy within a load
of coal, I.e" while Ute average sulfur
content of a total load of coal may be
wIthin acCeptable limits In relation to a
control regulation which restricts the
sulfur content of coal, it Is probable that
portions of the coal may have a sulfur
content above tQe allowable level. Simi-
larly. when fuel oils of different specific
gravities are 9tored within a common
tank such fuel oils tend to stratify and
may' not be a homogeneous mixture.
Thus. at times. fuel 011 In excess of allow-
able limits may be combusted. The QUes-
tion which arises Is whether the combus-
tion of this higher sulfur coal or 011 Is a
violation of an applicable sulfur con ten t
regulation. Initial investigations of this
Issue have indicated a relative lack of
6pecificity on the subject..
The Agency Is confronted with this
problem not only In relation to specifying
procedures for ithe emission reporting re-
Quirements for existing sources but also
in relation to enforcement consldem.tlons
for new sources affected by New Source
Performance Standards. At thia time, a
more thorough investigation of the si.tu-
ation in neoessalT prior to promulgation
of procedures dealing with fuel analysis
for both 011 and coal. At the conclusion
of this investigation, the Agency will set
fol'th Its findings and provide guidance
to State and local control agencies on
this issue. In the meantime, the portion
of the proposed regulaltions dealing with
fuel analysis Is being withheld from pro-
mulgation at this time. As such, States
shall not be required to adopt provisions
dealing with emission monitoring or re-
porting of sulfur dioxide emissions from
those sources where the Sta.tes may
choose to allow the option of fuel anal-
ysis as an alternative .to sulfur dioxide
monitoring. However. since the fuel
analysis alternative mav not be utilized
by a source that has installed sulfur di-
oxide control equipment (scrubbers).
States shall set forth legally enforceable
procedures which require emission moni-
tors on such sources, where these emis-
sion monitoring regulations otherwise
reqUIre their iTlStallatlon.
Othl?T' Modillcations to Proposed Reg-
ulations. In addition to reducing the
number of monitors required under the
proposed reguiatioTlS. a number ofmedi;
fications to various procedures m th
proposed regulations have. been coni
sidered and are included m the fina
regulations. One modification which has
been made is the deletion of the reqUire-
ment to instaJ] continuous monitors at
"the most representative" location. The
final regulations require ithe placement
of an emission monitor at "a representa-
tive" location in the exhaust gas system.
In many cases "the most representative"
loca-tlon may be difficult to locate and
may be inaccessible wi.thout new plat-
forms, ladders, etc., being insta.lled. Fur-
ther, other representative locations ca.n
provide adequate information on pollut-
ant emissions If minimum cntena for
selection of monitoring locations are ob-
served. Guidance in detcrm~g a repre-
sentative sampling" location IS contained
within th~ Performance ~peclfica.tl~n
foe each pollutant monitor In the emIS-
sion monitoring regulaltions for New
Source Performance Standards (Appen-
dix B Part 60 of this Chapter). While
these' criteria are designed for new
sources. they are also useful In deter-
mining representative locations for ex-
isting sources.
A further modification to the proposed
regulation Is the deletion of the require-
ment for new performance tests when
continuous emission monitoring equip-
ment.1S modified or repaired. As pro-
posed. the regulation would have re-
Quired a new performance test whenever
any part of the continuous enusslon
monitoring system was replaced. This
requirement was originally incorporated
In the regulations to assure the use of
a well-calibrated. finely tuned monitor.
Commentors pointed out that the re-
Quirement of conducting new perform-
ance tests whenever any part of an in-
strument Is changed or replaced is costly
and In many cases not-required. Upon
evaluation of this comment. the Admin-
Istrator concurs that performance tests
are not required after each repair or re-
placement to the system. Appropriate
changes have been made to the regula-
tions to delete the requlrements for new
performance tests. However. the final
regulations require the reportinK of the
various repairs made to the emission
monitoring syStem durin!!: each Quarter
to the State. Further. the State must
have nrocedures to require sources to re-
port to the State on a Quarterly basis in-
formation on the amount of time and the
reason why the continuous monitor wa5
not in operation. Also the State must
have legally enforceable procedures to
reouire a source to conduct a new per-
formance te5t whenever. on the basis of
available information. the State deems
such test is necessary.
The timp period proposed for the in-
s\!lllation of the reouired monitorine
w5tem. i.e.. one vpar after plan apnrovnl.
was thoul!"ht bv 21 commentor5 to be too
hrlpf. nrlmarilv because of lack of avail-
able instruments. the lack of tramed ner-
~onnel and the time available for in5tnl-
lation of the reQuired monitor- EQuip-
ment supollers were contacted bv the
Al1:encv and thev confirmed the ilVall-
ability of emission monitors. However.
FEDERAL REGISTER, VOL. 40, NO. 194--MONDAY, OCToaER 6, 1975
54
-------
the Administrator has detennlned that
the time necessary for purchase, Instal-
lation and performance testing of such
monitors may require more than one
year for certain installations, especially
where gaseous monitors are required. In
order to provide sources with ample time,
the Agency has modified the final regula-
tiOns to allow States to adopt procedures
that wlll provide sources 18 months' after
the approval or promulgation of the re-
vised, SIP to satisfy the Installation and
performance testing procedures required
by these continuous monitoring regula-
tions. A provision Is also included to al-
low. on a case-by-case basis, additional
extensions for sources where good faith
efforts have been undertaken to purchase
and install equipment, but where such
installation cannot be accomplished
within the time period prescribed by
the regulations.
A number of State and local agencies
also commented on the lack of time pro-
vided sources to Install the monitors re-
Quired by the proposed regulations.
These agencies also Indicated that they
must acquire sufilclent skllled manpower
to Implement the regulations, such as
personnel to provide guidance to sources,
to monitor performance te8ts and to
analyze the emission data that are to be
submitted by the sources. Further, some
State agencies Indicated that more than
six manths was needed to develop the
necessary plan revisions. Most State
agencies who commented stated that one
year should be provided to allow States
to revise their SIP's.. The Administrator
is aware of the various priorities which
confront State and local agencies at this
time (e.g., compliance schedules. enforce-
ment actions, litigation proceedings. re-
evaluation ot adequacy of SIP's to attain
and maintain national standards. etc.)
and, as such, believes that a six-month
postponement In the submittal of plan
revisions to require emission monitoring
and reporting is Justified and prudent.
Hence, States must submit plan revisions
to satisfy the requirements of this sec-
tion within one year of promulgation of
these regulations In the FEDERAL REGIS-
TER. However, States are advised that
such plan revisions may be submitted
any time prior to the final date. and are
encouraged to do so where possible.
The proposed regulations provided the
States with the option ot allowing sources
to continue to use emission monitoring
eqUipment that does not meet perform-
ance specifications set forth in the regu-
lations for up to five years from the date
of approval of the 'State regulations or
EPA promulgation. Some commenters
asked that this provision be extanded
Indefinitely. In some cases they indicated
they had recently purchased and had
already Installed monitoring systems
which were only marginally away from
meet10g the applicable performance spec-
ificatIOns. The Agency helieves. how-
ever, that such a modification to the pro-
posed regulations should not be allowed.
It is believed that such a provision would
result in inadequate monitoring systems
being maintained after their useful Ufe
has ended. Though some monitoring sys-
RULES AND REGULATIONS
terns wlll probablY last longer than five
years. it is beheved that thIS time period
w1l\ provide adequate time to amortize
the cost of such eqUipment. In cases
where existing emission monitors are
known not to provide reasonable esti-
mates of emissions, States should con-
sider more stringent procedures to pro-
vide a more speedy retirement of such
emission monitoring systems.
Some commentors raised the question
of whether eXisting oxygen monitors
which are Installed in most fossil fuel-
fired stearn generating boilers to monitor
excess oxygen for the purposes of com-
bustion control could be used to satisfy
the requirement for monitoring oxygen
under the proposal. Upon Investigation,
it' has been determined that, in some
cases, such oxygen monitors may be used
provided that they are located so that
there is no influx of dilution air between
the oxygen monitor and the continuous
pollutant monitor. In some cases, it may
be possible to iI1Stali the continuous
monitorin&.. device at the same location
as the existing oxygen monitor. Care
should be taken, however, to assure that
a representative sample Is obtained. Be-
cause of the various possiblllties that
may arise concerning the usefulness of
existing oxygen monitors, the State
should determine, after a case-by-<:ase
review, th~ acceptability of existing oxy-
gen [!Ionltors.
Another technical issue which was
raised suggested that continuous emis-
sion monitors which provide direct
measurements of pollutants in units com-
parable to the emission limitations and
other devices not specifically Identified
In the proposed regulations are avail-
able for purchase and Installation. The
Agency is aware that various monitor-
Ing systems exist but has not as yet de-
tennined specific performance specifica-
tions for these monitoring systems that
are directly applicable to the source
categories covered by these regulations.
However. it Is not EPA's intent to deny
the use of any equipment that can be
demonstrated to be rellable and accurate.
If monitors can be demonstrated to pro-
vide the same relative degree of accuracy
and durab1l1 ty as provided by the per-
formance specifications in Appendix B
of Part 60, they shall generally be ac-
ceptable to satisfy the requirements of
these regulations under Section 3.9 of
Appendix P. Further. where alternative
procedures (e.g.. alternate procedures
for conversion of data to umts of appli-
cable regulations) can be shown by the
State to be equivalent to the procedures
set forth In Appendix P of these regula-
tions, then such alternate procedures
may be submitted by the State for ap-
proval by EPA. Section 3.9 of Appendix P
identifies certain examples where alter-
native emission monitoring systems or
alternative procedures will generally be
considered by the Agency for approval.
It should be noted that some sources
may be unable to comply with the regu-
lations because of technical difflculties,
(e.g.. the presence of condensed water
vapor in the flue gas), physical limita-
tions of accessibility at the plant facility.
i624 ;j
or. in other cases, because of exueme
economic hardship. States should use
their judgment in Implementmg these
requirements in such cases. SectIOn 6 of
Appendix P of this Part provides \'anous
examgles where the Installation 01 con-
tinuous emj,ssion monitors would not be
feasible or reasonable. In such cases
alternate emissIOn monitoring \ and re-
porting) by more routine methods. such
as manual stack testing. must be re-
Quired. States in preparing their revised
SIP must set forth and describe the cn-
teria they will use to identify suc h un-
us'lal' cases. and must further describe
the alternative procedures they will im-
plement to otherwise satisfy the mtent of
these regulatIOns. States are advised that
this provision IS intended for unusual
cases, and, as such. should not be widely
applied.
It was pointed out by some com-
mentors that carbon dioxide monitors
could probably be used In lieu of oxygen
monitors to provide information to con-
vert emission data to the units of the
appllcable State regulation. Detailed
discussion of the technical men ts and
limitations of this approach Is discussed
In the Preamble to the Part 60 Regula-
tions. As pointed out in that Preamble.
such monitors may be used in certain
situations. Modifications have therefore
been made to the Part 51 regulatIOns to
allow the use of such monitors which 10-
clade references to technical specIfica-
tions contained in Part 60 for carbon di-
oxide monitors. Also, the cycling tIme for
oxygen monitors has been changed from
one hour to 15 minutes to correspcnd to
the specification in Part 60. The differ-
ence between cycling times In the two
proposals was an oversight. The cycling
time for carbon dioxide monitors will
also be 15 minutes as in Part 60.
A number of other miscellaneous tech-
nical comments were also received. Com-
mentors indicated that the proposed ex-
emption for opacity monitoring requIre-
ments that may be granted to Oil-fired
and gas-fired steam generators ,hould
also apply to units burning a combina-
tion of these fuels. The AdmInistrator
concurs with this suggestion and an ex-
emption for such sources burning oIl and
gas has ben provided in the final regu-
lations subject to the same restnctlons
as are imposed on oil-fired steam
generators.
As prevIOusly indicated. the regula-
tions for emission momtormg for eXist-
ing sources refer in many cases to the
specific performance specificatIOns .,et
brth in the emission momtoring rpgula-
tions for new sources affected by Part 60.
Many 'of the comments receIved on the
proposed regulation!! m effect pomted to
Issues affecting both proposals. In man:..
cases. more specific techmcal Issues are
discussed In the Preamble to the Part 60
Regulations and as such the readpr '"
referred to that Preamble Speclfj"ally.
the Part 60 Preamble addresses the fol-
lowing toPICS: data handling and If'port-
ing techniques: requirements for report-
ing repairs and replacement parts used:
location of momtoring instrumen IS.
changes to span reqUirements, operatmg
FEDERAL REGISTER. VOL. 40, NO. 194-MONDAY, OCTOBER 6. 1975
55
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11;211;
!n:quency requlremenb;. sulfuric acid and
mtnc acid plant conversIon factors:
and. for opacity monitonng equipment,
changes in the cycling tIme and m align-
ment procedures. The reader is cau-
tioned, however, that specIfic reference
to regulations in the Part 60 Preamble
is stnctly to federal New Source Perform-
ance Regulations rather than State and
local control agency regulations which
affect existing sources and which are part
of an applicable plan,
In addition to the many technical
comments received, a number of legal
issues were raised. Several commentors
questioned'EPA's statutory authority to
promulgate these regulations and pointed
out other alleged legal defects In the pro-
posal. The Administrator has considered
these comments, and has found them un-
pCrl,Ua)'o,lVf"
One commentor argued that new 40
cm 5119'1') will require "revisions" to
eXIsting state plans; that "rev1slons" may
be called for under Section 110(&) (2(8)
of the Clean Air Act only where EPA has
found that there are "Improved or more
expeditious methods" for achieving am-
bient standards or that a state plan Is
"substantially Inadequate" to achieve the
standards: that the new regulation Is
based upon neither of these findings; and
that therefore there is no statutory au-
thorIty for the regulation. This argu-
ment fails to take cognizance of Section
1101a) (2) IF) IIi) of the Act, which man-
dates that all state implementation plalUl
contam' selr-monltorlng requirements.
The fact that EPA originally accepted
plans without these requirements be-
cause of substantial uncertainty as to the
reliabilitv of self-monitoring equipment
does not ne~ate the mandate of the
statute.
In essence, new ~ 51.19(1') does not caU
for "revisions" as contemplated .by the
Act, but for supplements to the original
plans to make them complete. At any
rate, it Is the Administrator's judgment
tha t the new self -monitoring require-
ments will result in a "more expeditious"
achIevement of the ambient standards.
Since these requirements are valuable
enforcement tool5 and indicators of mal-
functions, they should lead to a net de-
crease in emis510ns.
Other commentors argued that even if
F.PA has statutOry authority to require
self-momtoring, It has no authority to
Impose specIfic minimum requirements
for state plans, to require "continuous"
momtoring, or to require monitoring of
oxygen. which is not a pollutant. These
comments fall to consider that a basic
pre. ,,;)t of admmistratlve law IS that an
ag~ . y may fill in the broad directives of
leg: ,tion with precise regulatory re-
qUI! lents. More specifically, the Ad-
mlr." rator has authority under Section
30 I r J. of the Clean Air Act to promul-
gate "such regulations as are necessary
to carry out his functions under the Act".
Courts have long upheld the authority of
a!!cncies to promulgate more specific re-
qUIrements than are set forth In en-
ablin!: lel{islation, so long as the require-
ments are reasonably related to the pur-
poses of the legislation Since the Act
RULES AND REGULATIONS
reqUires self-monitoring without further
guidance, EPA surely has the authority
to set specific requirements in order to
carry out its function of assuring that the
Act is properly implemented.
In EPA's judgment, the requirements
set forth in fi 51.19(1') are necessary to
assure that each state's selr-monitoring
program is sufl1clent to comply with the
Act's mandate. The fact that oxygen and
carbon dioxide are not air pollutants
controUed under the Act is legally ir-
relevant, since in EPA's judgment, they
must be monito"ed In order to convert
measured emission data to units of emis-
sion standards,
Other commentors have argued that
the self-monitoring requirements violate
the protection I!.ltainst self-Incrimination
provided in the Fifth Amendment to the
U.S. Constitution, and that the Informa-
tion obtained from the monitoring Is so
unreliable as to be invalid evidence for
use In court.
There are two reasons why the self-
Incrimination argument Is Invalid. First,
the selr-Incrlminatlon privilege does not
apply to corporations, and It Is probable
that a great majority of the sources cov-
ered by these requirements wiU be owned
by corporations. Secondly, courts have
continually recognized an exception to
the privilege for "records required. by
law", such as the self-monitoring and
reporting procedures which a.re required
by the Clean Air Act. As to the validity
of evidence issue, in EPA's opinion, the
required performance specifications will
assure that self-monitoring equipment
will be sufliclentlv reliable to withstand
attacka In court.
Fln&lly, some comments refiected a
misunderstanding of EPA's suggestion
that states explore with counsel ways to
draft their regulations so as to automati-
cally Incorporate by reference .future
a4dttlons to Appendix P and avoId the
time-consuming plan revision process.
(EPA pointed out that public participa~
tion would stili be assured, since EPA's
proposed revisions to Appendix P would
always be subJect to public comment on
a nation-wide basis.)
EPA's purpose was merely to suggest
an approach that a state may wish to
follow il the approach would be legal
under that state's law. EPA offers no
opinion as to whether any state law
would allow this. Such a determination
is up to the Individual states.
Summary 01 Revisions and Clarillca-
tiom to the Proposed. Requlaticms.
Briefiy, the revisions and clarifications' to
the proposed regulations include:
II) A clarification to indicate that con-
tinuous emission monitors are not re-
quired for sources unless such sources
are subject to an applicable emission
limitation of an approved SIP.
(2) A revision to require emission
monitors for oxides of nitrogen- in only
those AQCR's where the Administrator
has specifically called tor a control
strategy tor nitrogen dioxide.
13) A revision to include a general pro-
vision to exempt any source that clearly
demonstrates that It wiJI cease operation
within nve years of the inclusion ot moni-
toring reqUlremenb; for the source in
Appendix P. .
(4) Revisions to exempt smaller-sized
sources and infrequently used sources
withJn the specified source categories.
(5) A revisIOn to the data reporting
requirements to require the submittal by
the source ot the State, emission data In
excess of the applicable emission limita-
tion for both opacity and gaseous pol-
lutants, rather than all measured data, as
proposed. A. provision has been added to
require Information on, the cause of all
noted violations of applicable regulations.
(6) A clarification to indicate that the
continuous monitoring of oxygen is not
required unless the continuous monitor-
Ing of sulfur dioxide and/or nitrogen
oxides emissions Is required by the appli-
cable SIP.
(7) A revision to allow the placement
of continuous emission monl1lors at "a
representative location" on the exhaust
gas system rather than at "the most
representative location" as reqUIred by
the proposed regulatIOns.
(8) A revision to delete the require-
ments of new pertormance tests each
time the continuous monitoring equip-
ment is repaired or: modified. However, a
new provision Is. Included to require that
a report of all repairs and maintenance
performed during the quarter shaJJ be re-
ported by the source to the State.
(9) A modification to provide sources
18 months rather than one year after
approval or promulgation of the revised
SIP to comply with the continuous moni-
toring regulations adopted by the States.
(10) A modification to provide States
one year, rather than the six months
after the promulgation of these regula-
tions in the FEDERAL REGIS'1'ER to submit
plan.revlsions to satisfy the requirements
promulgated herein.
Requirements 01 States. States shaJJ be
required to revise their SIP's by Octo-
ber 6, 1976 to Include legaUy enforceable
procedures to require emission monitor-
ing, recording and reporting. as a mini-
mum for those sources specified in the
regulations promulgated herein. While
minimum requirements have been estab-
lished. States may, as they deem appro-
priate, expand these requirements.
The regulations promulgated herein
have been revised in light of the vanous
commenb;' to generally provide a more
limited introduction into this new meth-
odology. Cooperation among atIected
parties, 1.1'.. State and local control agen-
cies. sources. instrument manufacturers
and suppliers, and this Agency is neces-
sary to move successfuJJy forward in
these' areas of emission monitoring and
reporting prescribed In the Clean Air
Act. Assistance can be obtained from the
EPA Regional Omces In relation to the
technical and procedural aspects of these
regulations.
Copies of documents referenced In this
Preamble are available for public Inspec-
. tlon at the EPA Freedom of Information
Center, 401 M Street. S.W.. Washington,
D,C. 20460. The Agency has not pre-
pared an environmental Impact state-
ment for these regulations since they
FEDERAL REGISTEI, VOL. 40, NO. 194-MONDAV, OCTOIEI 6, 1975
56
-------
were proposed (September 11. 19741 prior
to the effective date for requiring volun-
tary environmental impact statements
on EPA's regulatory actions (see 39 FR
16186, May 7, 1974).
The regulations set forth below are
promulgated under the authority of sec-
tions 110(a) (2) (F) (\i)-(ill> and 301<1\)
of the Clean Air Act. as amenqed [42
U.S.C. 1857c-5(a) (2) (F) (!i)-(iU>. 1857g
(a)] and are effective November 5, 1975.
Dated: September 23, 1975.
JOHN QuARLES,
Acting Administrator.
R--CES
1. Jenkins, R. E.. Strategies and Air Stsnd-
ards Division, OAQPS. EPA. Memo to R. L.
Ajax. Emission Standards and Engineering
DIvision. OAQPS. EPA. Emission Monitoring
Costs. February 27, 1975.
Z. Young, D. E.. Control Progrsms Develop-
ment Division, OAQPS, EPA. Memo to E. J.
Lillis, Control Programa Development DI-
vision. OAQPS. EPA. Emtsslon Source Data
for In-Stack Monitoring Regulations. June 4.
1971.
1. Section 51.1 Is amended by adding
paragraphs (z). (aa), (bb). (CC). (dd),
and (ee) as follows:
1151.1
Definitions.
(z) "EnUsslon standard" means a reg-
ulation (or portion thereof) setting forth
an allowable rate of emissions, level of
opacity. or prescribing equipment or fuel
specifications that result In control of
air pollution emissions.
(aa) "Capacity factor" means the
ratio of the average load on a machine or
equipment for the period of time consid-
ered. to the capacity rating of the ma-
chine or equipment.
(bb I "Excess emissions" means emis-
sions of an air pollutant in excess of an
emission standard.
(cc) "Nitric acid plant" means any fa-
cil1ty producing nitric acid 30 to 70 per-
cent In strength by either the pressure or
atmospheric pressure process.
(dd) "Sulfuric acid plant" means any
facil1ty producing sulfuric acid by the
contact process by burning elemental sul-
fur, alkylation acid. hydrogen sulfide, or
acid sludge. but does not Include facil1-
ties where conv~sion to sulfuric acid Is
utilized primarilY as a means of prevent-
ing emissions to the atmosphere of sul-
fur dioxide or other sulfur compounds.
(ee) "Fossil fuel-fired steam gener-
ator" mellIlS a furnace or boiler used in
the process of burning f ossU fuel for the
primary purpose of producing steam by
heat transfer.
2. Section 51.19 Is amended by adding
paragraph (e) as follows:
II 51.19
Sour~e surveillance.
(e) Legally enforceable procedures to
require stationary sources subject to
emission standards as part of an appl1-
cable plan to install, cal1brate, maintain,
and operate equipment for continuously
monitoring and recording emissions: and
to provide other information as specified
in Appendix P of this part.
RULES AND REGULATIONS
(1) Such procedures shall identify the
types of sources. by source category and
capacity. that must install such instru-
ments, and shall identify for each source
category the pollutants which must be
monitored.
(2) Such procedures shall, as a mini-
mum. require the types of sources set
forth In Appendix P of this part (as such
appendix may be amended from time to
time) to meet the appl1cable require-
ments set forth therein.
(3) Such procedures shall contain pro-
visions which require the owner or op-
erator of each source subject to continu-
ous emission monitoring and recording
requirements to maintain a file of eJl
pertinent information. Such information
shall Include emission measurements.
continuous monitoring system perform-
ance testing measurements, performance
evaluations. calibration checks. and ad-
justments and maintenance performed
on such monitoring systems and other re-
ports and records required by Appendix
P of thfs Part for at least two years fol-
lowing the date of such measurements or
maintenance.
(4) Such procedures'shall require the
source owner or operator to submit in-
formation relating to emissions and
operation of the emission monitors to the
State to the extent described in Appendix
P as frequently or more frequently (\S
described therein. .
t 5) Such procedures sheJl provide that
sources subject to the requirements of
~ 51.19(e) (2) of this section shall have
installed all necessary equipment and
shall have begun monitoring and record-
ing within 18 months of (1) the approval
of a State plan requiring monitoring for
that source or (2) promulgation by the
Agency of monitoring requirements for
that source. However, sources that have
made good faith efforts to purchase. In-
stall. and begin the monitoring and re-
cording of emission data but who have
been unable to complete such installa-
tion within the time period provided may
be given reasonable extensions of time as
deemed appropriate by the State.
(6) States shall submit revisions to the
applicable plan which implement the
provisions of this section by October 6.
1976.
3. In Part 51. Appendix P Is added as
follows:
ApPENDIX P-MINII4UY EMISSION MONITORING
RZQUtllDlItNTS
1.0 Purpose. This AppendlE P sets forth
the minimum requirements for continuou8
eml..lo~ monItoring and recordIng that each
State Implementation Plan must Include In
order to be approved under the provisions of
40 CPR 51.10(e). These requirements Include
the source -=ategorles to be affected; emlselon
monitoring, recording. and reporting re-
quirements :or these sources; performance
specUlcatlons for accuracy, reliability. and
durability C'f acceptable monitorIng systems:
and techniques to convert emission data to
units of the applicable State emission stand-
ard. Such data must be reported to the State
as an Indication of whether proper mainte-
nance and operating procedures are being
utilized by source opera to.... to maIntain
emission levels at or below emission stand-
ards. Such data may be used directly or In-
11)2.17
directly for compliance determination or any
other purpose de-emed appropriate by the
State. Though the monitoring requtremt>nts
are specified In detail. States are gl\.en ,,>orne
ftexlblllty to resolve dlfflcultles that may
arise during the implementation or these
regulations.
1.1 .(pplicability.
The State plan shaH require the owner or
operator of Pon em1.llsion source In a category
listed In-this Appendix to: (I) Install. call-
brate. operate. and maintain all monitoring
equipment necessary for continuously monl~
torlng the pollutants specilled In this Ap-
pendlE for the applicable source category:
and (2) complete the Installation and per-
formance tests of such equIpment and begin
monitoring and recording within 18 months
of plan approval or promulgation. The source
categories and the respective monitoring re-
quirements are listed below.
1.1.1 Fossll fuel-fired steam generators. as
speclfted In paragTaph 2.1 of this appendix.
shall be monItored for opacity, nitrogen
oxides emissions. sulfur dioxide emissions.
and oxygen or carbon dioxide.
1.1.2 Fluid bed catalytic cracking unit
catalyst regenerato..... as speclfted In para-
graph 2.4 of this appendix, shall be moni-
tored for opacity,
1.1.3 Sulfuric acid plants. as spe<:lfted In
paragraph 2 3 of this appendix. shall be
monitored for sulfur dioxide emissIons.
1.1.4 NitrIc acid plants. as speclfted In
paragraph 2.2 of this appendix. shall be
monitored for nitrogen oxides emissions.
1.2 Exemption!.
The States may Include provisions wIthin
their regulatl9ns to grant exemptions trom
the monitoring requirements of paragraph
1.1 of this Rppendlx for any source which Is:
1.2.1 subject to a new source performance
standard promulgated In 40 CFR Part 60
pursuant to Section III of the Clean Air
Act; or
1.2.2. not subject to an applicable oml.'5lon
standard of an approved plan; or
1.23 scheduled for retirement wt thl n 5
yea.rs a.fter Inc.uslan of monitoring requlre~
ments for the source In AppendIx P. provIded
that adequate evidence and gua.rantet'') are
proVided that clearly show that the ~ourc.p.
will cease operations prior to such date
1.3 Exton.io,u.
States may allow rea.sonahle extensions of
the time provided for installation of monitors
for facllltles unable to meet the prescribed
tlmefra.me (t e.. 18 months from plan ap-
proval ar promulga.tlon I provided the owner
or operator of such facUlty demonstrates that
good faith etrorts have been made to obtain
and Install such devices within such pre~
scribed tlmeframe.
1.4 Monltonng Sy.fom Malfunction
The State pbn may provide a temporary
exemption from the monitoring a.nd report-
Ing requirements of this appendix durlnl( i'J1V
period of monitoring system malfunction.
provided tha.t the source owner or opera.tor
'shows. to the satisfaction of the Stat~, that
the malfunction was unavoidable and 15
being repaired as e~pedltlously as practicable
20 .\f'lnlmum Mcrnttoring RequlTe"11ent
Sta.tes must, as a minimum. require the
sources listed In paragraph 1.1 of this <1ppen~
dtx to meet the following baste requirements
2.1 Fossil luel~fiTed steam geneTaton
Each fossll fuel~ftred steam generat0f, ex-
cept as provided 1n the following subpara.-
graphs. with a.n annual a.verage capacity fac~
tor of greater than 30 percent, as reported to
the Federal Power Commission for calendar
yea.r 1974. or as otherWise demon!"itr:\.ted to
the State by the owner or operator. sha.iJ (on-
form with the followlnR monitorIng re(~IJJrt~.
ments when such facility Is subjec,; (0 an
emission standard of an a.pplicable plan for
the pollutant 1n quesuon
FEDERAL REGISTER, VOL. 40, NO. 194-MONDAY, OCTOBER 6, 1975
57
-------
162-18
2 1.1 A continuous monltortng system for
thl'l measurement of opacity which meeta the
performance specificaUons of paragraph
J I 1 of this appendix shall be Installed. call-
hr:J.tec. malntalnec1. and operated 10 accord-
ance '...'Ith the procedures of this appendix by
the owner or operator of a.ny such stea.rn
jo{f'nerator ot greater than 250 miUion BTU
per hour heat input except where:
2 1 1.1 gaseous fuel Is the only fuel burned.
or
~ 1 I 2 011 or a mixture of gas and 011 a...
the only fuels burned and. the source 15 able
to "omply WIth the applicable particulate
matter and opacity regulations WIthout utili-
zation of particulate ma.tter collection
equipment, Bond where the SOUf'Ct!' has never
heen found. through any admlnJstnLtlve or
Judicial proceedings. to be in violation of any
visIble emission standard of the applicable
plan
2 1 2 A continuous monltor1n~ system for
the mea.surement of sultur dtoxide Which
mef!'ts the performance specincatlcDs of para-
~aph 3 I 3 of this appendix shall be Installed.
calibrated, maintained. and operated on any
(ossl1 fuel-ftred steam genera.tor of gre&ter
than 250 million BTU per hour heILt Input
which has Installed sulfur dioxide pollutant
rt1ntrol equipment
2 1 3 A contin uous monitoring system tor
rhp measurement ot n~trogen oxides which
meets the pf'rtormance spec1ftc&tton of pua-
graph 3 I 2 of this appendix ahall be Installed.-
ralt.)ra.ted. maintained. a.nd operated on foe",
511 fuel-fired steam Rene-ra.tors of greater
than 1000 million BTU p~r hour heat Input
when ,uch fa<:l1Ity Is located In an Air Qual-
tty Control ReRion where the Adm1nLstrator
has specifically determined thILt a control
stratt'gy for nitrogen dioxide 15 necessary to
f\ttBln -the national standards. unless the
source owner or operator demonstt'ates dur-
Ing source compll&llc~ testa ... required by
thp State that such. ,ouree. emits nltroaen
""(ldes at 1evels 30 percent or more below the
~ml""lon standard within the ILppllcable
pial)"
2 1" A continuous monitoring system for
the measurement of the percent oxygen or
carbon dioxide which meets the perform-
ance !lpeclftcat1ons of paragraphs 3.1 4 or
J 1 5 "f this appendix shall be Installed. cali-
brated. ope-rated. and matnta1ned on f05811
fuel.fired steam generators where measure-
ments of oxygen or carbon dto~tde tn the flue
gas are re-qulred to convert etther sulfur di-
oxide or nttmgen oxtdes conUnuous emts-
stan monttortnliC data. or both. to units of
thp" emtsslon standard within the appl1ca-
"Ie plan
22 Nitnc acid plants.
Each nitric. acid plant of greater thsn 300
ton" per day production c&pactty. the pro-
duc'lon capa<:lty being expressed ... 100 per-
cent acid. located In an Air Quality Control
Re~lon where the Administrator has speclf-
jr-a)Iy determined that a control strategy for
rutro~en dioxide 15 necessary to atta1D the
nati,~nal standard shall tnstan. calibrate.
matnta1n. and operate a continuous mont-
~OT1 ~IS <>vstem for the meRSurement of nltro-
;f'! oxides which meets the performance
"'pl' "icat1ons of paragraph 3 1 2 ror each
n1 aCid producing facility wIthin such
pi..
23 [!UTIC acid plants
1=:a, 1 Sulfuric acid plant of greater than
300 t ,ns per day producUon capacity. the
p!"(',ductlan ~Ing expressed as 100 percent
'\('Id. shall Install. cal1brate. malntatn and
operate a continuous monttorlng system for
the measurement of sul.fur dioxide which
'T1~e~s the performance spectftcat10ns of 3 1.3
for each sulfuric acid producing ~fac1l1ty
'...:.hln such plant
24 Fluid ht"d catalytic cTacklng unIt cata-
:y~t regt"ntTaton at petroleum reflntrit"
RULES AND REGULATIONS
Each catalyst regenerator for ftuld bed
catalytic cracking unlta of greater than 20.-
000 barrel. per day freah ,teed capacIty shall
Install. calibrate. maintain. and operate a
continuous monitoring system for the meas-
urement of opactty whtch meets the per-
formance spectncat10ns of 3.1.1.
3.0 Minimum specifications.
All State- plans shall require owners or op-
erators of monitOring equipment Installed
to comply with thls'Appendlx. except as pro-
vided In paragraph 3.2. to demonstrate com-
pliance with the foJlowlng performance spec-
I1Ica tlons.
3 1 Performance specifications.
The performance speclllcatlons set forth
In Appendix B of Part 60 are Incorporated
herein by reference. and shall be used by
States to det.ermine accept&bUlty of monitol'-
ing equipment Installed pursuant to this
Appendix except that (I) where reference Is
m..de to the" A,dmrnlStrator" In Appendix B.
Part 60. the term "State" should be Inserted
for the purpose of this Appendix I e.g.. In
Performance Specl1lcatlon I. 1.2. ". . . moni-
toring systems subject to approval by the
Adminutrator:' should be Interpreted as.
. . monitoring systems subject to approval
by the State"). and (2) where reference Is
made to the "Reference Method" In Appendix
B. Part 60. the State may allow the use of
ei ther the State approved reference method
or the Federally approved reference method
as published In Part 60 of this Chapter. The
Performance Speclftcatlons to be used with
each type of monitor1ng syste'm are Usted
below.
3 1.1 Continuous monitoring systems for
measuring opacity shall comply with Per-
formance Speclftcatlon I.
3 I 2 Continuous monitoring systems for
meaaurlng nitrogen oxides shall comply wIth
Performance Speclftcatlon 2.
3 1.3 Continuous monitoring systems for
measunng sulfur dioxide shall comply with
Performance Specification 2.
3 I 4 Continuous monitoring systems for
measuring oxygen shall comply with Per-
formance Specification 3.
31.5 Continuous monitoring systems for
measuring carbon dioxide shall comply with
Performanc...speclOcation 3.
3.2 E:zempUmu.
Any source whiCh haa purchased an emla-
slon monitoring system Isl prior to S~ptem-
ber 11. 1974. may be exempt from meeting
suCh test procedures prescribed In Appendix
B of Part 60 for a period not to exceed ftve
years Crom plan approval or promulgation.
S.3 CalibraUon G",e..
For nitrogen oxides monitoring sy.tems In-
stalled on foull fuel-fired steam generators
the pollutant gaa used to prepare calibration
gas mixtures (Section 2.1. Performance Spec-
I1Ication 2. Appendix B. Part 60) ahall.. be
nItric oxide I NO). For nitrogen oxides mon-
Itoring systems. Installed on nitric acid plants
the pollutant gas used to prepare calibration
gas mixtures (Section 2.1. Performance Spec-
lOcation 2. !.ppendlx B. Part 60 of thIS Chap-
ter) shall be nitrogen dioxide I NO.). These
gases shall also be used for dally checks under
paragraph' 3.7 of this appendix all applicable.
For sulfur dioxide monitoring systems in-
stalled on fossil fuel-ftred steam generators
or sulfuric acid plants the pollutant gas used
to prepare calibration gaa mixtures I Section
21. Performance SpeclftcaUon 2. Appendix B.
Part 60 of this Chapter) shall be sulfur di-
oxide ISO,I. Span and zero gases should be
traceable to National Bureau of Standards
reCerenee gases whenever these reCefence
gases are available. Every stx months from
date of manufacture. span and' zero gases
shall be reanalyzed by conducting trtpllcate
analyses using the reference methods 10 Ap~
pendlx A. Part 60 of this chapter as follows'
for sulfur dioxide. use Reference Method 6;
tor nitrogen oXldes. use Reference !\tethod 7:
and for carbon dioxide or oxygen. use Ref.;
erence Method 3. The gases may be analyze
at less frequent tntervals if longer shelf l1ves
are guaranteed by tbe manufacturer
3.4 Cycling Umes
Cycling times Include the total tlme a
monitoring system requires to -'Oample.
analyze and record a.n emission measurement
3.4.1 Continuous monitoring systems for
measuring opacity shall complete a mini-
mum of one cycle of operation I sampling.
analyzing. and data recording) for each su~-
ce..lve lo-second period.
3.4.2 continuous monitoring systems for
measuring oxides of nitrogen. carbon diox-
Ide. oxygen. or sulfur dioxide shall complete
a minimum of one cycle of operation (sam-
pling. analyzing, and data recording) for
each successive 15-mlnute period.
3.5 Monitor location.
State plans shall require aU contuluouS
monitorin, systems 'or mon1tOrlnli!: devices to
1>e Installed such that representatlve m.""-
urements of emissions or process para.meters
(1.e" oxvgen. or carbon dioxide) from the af-
fected facility are obtained. Additional guid-
ance for location of continuous monitoring
systems to obtain representative- samples are
contained In the applicable Performance
Specifications of Appendix B of Part 60 of
thiS Chapter.
36 CombIned ef1luents.
When the emuents from two or more af-
fected facl1!t1es of slmll..r design and operat-
ing charllcterist1cs are combtned before heing
released to the atmosphere. the State plan
may allow monitoring systems to be Installed
on the combined emuent. When the affected
fai:l1!tles are not of similar design and operat-
Ing characteristics. or when the emuent from
-cine atrected fa<:\1Ity Is released to the atmo.-
phere through more than one point. the State
should establish alternate procedures to Im-
plement the Intent of these requirements
3.7 Z","o and drtft.
State plans shall require owners or opera-
tors of all continuous monitoring systems
Installed In accordance WIth th~ requU'e-
ments of this Appendix to record the zero and
span drift In accordance with the method
prescribed by the manufacturer of such in-
strumenta: to subject the Instruments to the
man ufacturer's recommended. zero and span
check at least once dally unle" the manu-
facturer has recommended adJustmenta at
shorter Intervals. tn which case such recom-
mendations shall be followed: to adjust the
zero and span whenever the 24-hour zero
drift or 24-hour calibration drtft limits of
the applicable performance specifications in
Appendix B of Part 60 >Te exceeded: and to
adJust continuous monitoring systems refer-
enced by paragraph 3.2 of this Appendix
whenever the 24-hour zero drift or 24-hour
calibration drift ..ceed 10 percent of the
emission standard.
3.8 Span.
Instrument span should be approxlmatel\'
200 per cent of the expected Instrument data
display output corresponding to the emission
standard for the source.
39 Alternative procedures and rrquire-
menh.
In cases where States wish to utll\ze difl'er-
ent. but equivalent. procedures and require-
ments for continuous monttorlnj;t syswms.
the State plan must provide a description of
~uch alternative proceduers for approval by
the Administrator. Some examples oC situa-
tions that may re-quire alternatt\'~5 follow'
3.9.1 Alternative monitoring require-ments
to accommodate continuous monitortn~ S\'3~
terns that require corrections for stack mois-
ture condtttons (e.g.. an Instrument measur-
ing steam generator SO. emissions on a wet
basIs could be used wlth- an instrument 'mea-
sur1n~ oxygen concentration on a dry basis
1f acceptable methods of measuring stack
motsture conditions are used to al10w ac-
FEDERAL IEGISTEI. YOLo 40, NO. 194-MONDAV. OCTOBER 6. 1975
58
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curate adjustment of the. measured 50: con-
centration to dry basis)
3.92 Alternative locations for Installing
continuous mon1tortng systems or monitor-
lng devices when the owner or operator can
demonstrate that III-'tallation at alternative
locations w1l1 en&ble accurate and represent-
ative measurements.
3.9.3 Alternative procedures for perform-
Ing cal1bratton checks (e.g.. some instruments
may demonstrate superior drift characteris-
tics that require checking at leas frequent
Intervalsi.
3.9.4 Alternative monitoring requirements
when the ellluent from one all'ected facility or
the combined emuent from two or more
Identical all'ected facilities Is released to the
atmosphere through more than one point
le.g.. an extractive. gaseous monitoring sys-
tem used at several points may be approved
If the proced ures recommended are sui table
for generating accurate emission averages).
3.9.5 Alternative continuous monitoring
systems that do not meet the spectral re-
sponse requirements In Performance Speci-
fication I. Appencllx B of Part 50, but ade-
quately demonstrate a dellnlte and consistent
relationship between their measurements
and the opacity measurements of a system
complying with the requirements In Per-
formance Specification I. The State may re-
quire that such demonstration be performed
for each all'ected facility.
4.0 Minimum data requirementa.
The tbllowlng paragraphs set forth the
minimum data reporting rsqulrements neces-
sary to comply with 151.19(e) (3) &l\d 14).
4.1 The State plan ahall require owners
or operators of facilities required to Install
continuous monitoring syatems to submit a
wrttten report of excess emissions for each
calendar quarter and the nature and cause of
the excess emissions. if known. The averaging
period used for data reporting should be
established by the State to correspond to the
averaging period speCllled In the emission
test method uoed to determine compliance
with an emission standard for the pollutant.
source category In question. The required re-
port shall Include, as a minimum, the data
stipulated In this Appendix.
4.2 For opacity messuremente, the sum-
mary shall consist of the magnitude In actual
percent opacity of all one-minute (or such
other time period deemed appropriate by the
State I averages of opacity greatsr than the
opacity standard In the applicable plan for
each hour of operation of the facility. Aver-
age values may be obtained by Integration
over the averagtng period or by arithmeti-
cally averaging a minimum of four equally
spaced. Instantaneous opacity measurements
per minute Any time period exempted shall
be considered before determining the exceas
averages of opacity (e.g.. whenever a regu-
lation allows two minutes of opacity meas-
urements In excess of the stsndard, the State
shall require the source to report all opacity
averages. in anyone hour. tn excess of the
standard, minus the two-minute- exemp-
tlon). If more than one opacity standard
applies. exceSs emissions data must be sub-
mitted In relation to all such standards.
4.3 For gaseous measuremepts the sum-
mary shall consist of emission averages, In
the units of the applicable standard. for each
averaging period during which the appli-
cable standard was exceeded.
4.4 The date and time Identifying each
period during which the continuous moni-
toring system was Inoperative. except for
zero and span checka, and the nature of
system repairs or adjustments shall be re-
ported. The State may require proof of con-
ttnuous monitoring system performance
whenever system repatrs or adjustments have
heen made.
RULES AND REGULATIONS
4.5 When 1\0 excess emlsslons have oc.
curred and the conttnuous monitoring 5Y5-
tem(s) have not been inoperative. repaired.
or adjusted. such Information shall be In-
cluded In the report.
46 The State plan shall require owners or
operators of all'ected facilities to maintain
a file of all Information reported In the quar-
terly summaries. and aU otber data collected
either by the continuous monitoring system
or as neceasary to convert monitoring data
to the units of tbe appl1cable standard for.
a minimum of two years from the d"te of
collection of such data or submlsalon of
such summaries.
5.0 Data Reductian.
The State plan shall require owners or
operators of all'ected facilities to use the
following procedures for convertlns moni-
toring data to units of the stsndard where
necessary .
5.1 Por foasll fuel-fired steam generators
the following procedures shall be. used to
convert gaseous emission monitoring data in
parts per million to g/mlllion cal (\bl million
BTU) where necessary:
5.1.1 When the owner or operator of a
fOIls 11 fuel-llred steam It8nerator elects under
subparagraph 2.\.4 of this Appendix to meas-
ure oxygen In the fiuF gases, the measure-
ments of the pollutant concentration and
oxygen concentration shall each be on a dry
basis and the followIng conversIon procedure
used:
E=CF (20;~.~O,)
5.1.2 When the owner or operator elects
under subparagraph 2.1.4 of tbls Appendix
to measure carbon dioxide In the flue gases.
the m.aaurement of the pollutant concen-
tration and the carbon dioxide concenttatlon
sball each be on a consistent basis (wet or
dry) and the following conversion procedure
used:
E=CF, (%l~O,)
5.1.3 The values used In the equations un-
der paragraph 5.1 are derived as follows:
E= pollutant emission, g/mlllion
cal (\b/mllllon BTU).
C=pollutant concentration, gl
clacm (Ib/clacf). d~ermlned by
multiplying the average concen-
tration (ppm) for each hourly
period by 4.16 x 10--' M g/clacm
per ppm (2.64 x 10-' M Ib/clacf
per ppm) where M = pollutant
molecular weight, gig-mole (\bl
Ib-mole). M-= 64 for sulfur di-
oxide and 46 for oxides of nitro-
gen.
',0.. <;'OO.=o..ygen or carbon dioxide vol-
- - ume (expressed as percent) de-
termined with equipment spec-
Ified under paragrapb 4.1.4 of
this appendix.
F. P. = a factor representing a ratio of
the volume of dry flue gases
generated to the calorillc value
of the fuel com busted (F). and
a factor representing a ratio of
the volume of carbon dioxide
generated to the calorific v~ue
of the fuel com busted (F.) re-
spectively Values of P and P.
are given In ! 60.4S (t) of Part
60. as applicable.
5.2 For sulfuric acid plants the owner or
operator shall;
5.2.1 establish a conversion factor three
times dally according to the procedures to
! 60 84( b) of this chapter:
5.22 multiply the conversion factor b~ the
average sulfur dtoxlde concentration in the
1r,~I!J
ftue gases to obtain average ~llltt1r d!IIXldc
emts..c;lons ~n Kg/metrIc ton lIb. short tOil ~ .
and
52.3 report the average sulfur dloxlde
emIssion for each averaging period In e",("('<;5
of the appl1cable em1ss10n standard in the
quarterly summary.
5.3 For nttrtc acid plants the- owner or
operator shall;-
5.3.1 establish a con\"erslon factor i\L'cnrd-
Ing to the procedures of !6073Ib) or this
chapter.
5.3.2 multiply the conversion factor by the
average nttrogen oxides concentration Ln the
nue gases to obtain the nitrogen oxides emls.
slons In the units at the applicable standard:
5.3.3 report the average nitrogen oxides
emisston for each averaging pertod in excec;s
of the applicable emission standard. ,n the
quarterly summary.
5.4 Any State may allow data reporting
or reduction procedures varytng from those
set forth In this Appencllx If the owner or
operator of a soutce shows to the satisfacUon
of the State that his procedures are at least
as accurate as thoae In this Appendix. Such
procedures may Include but are not limited
to. the following.
5.4.1 Alternative procedures for computing
emtsston averages that do not require Inte-
gration of data (8 g.. some faclltttes mav dem.
onstrate that the variability of their em Is-
stoms 15 8u1ftctenotly small to allow accurate re-
duction of data based upon computing aver-
ages from equally spaced data points over the
averaging period) .
5.42 Alternative methods of converting pol-
lutant concentratton measurements to the
units of the emission standarels.
6.0 Special Con.ldeTation.
The State plan may provide for approval. on
a case-by-case basts. of alternative monHor-
tng requirements dUferent trom the provi-
sions of Parts I through 5 of this Appendix If
the provlslolUl of this Appendl)< (I e., the in-
stallation of a continuous emission monttor.
Ing system I cannot be Implemented by a
source due to physical plant limitations or
extreme economtc reasons. To make use of
this provIsIon, States must Include In their
plan spectftc crtteria for determining those
physical limitattons or extreme economic
situations to be considered by the State. In
such cases, when the State exempts any
source subject to this Appendix by use of this
provision from tnstalltng continuous em~5.
slon monitoring systems, the State shall set
forth alternative emisston monitorln~ and
reporting requtrements (e g.. periodic manual
stack tests I to satisfy the Intent of tbese
regulationa. Examples of such special c~'es
Include, but are not limited to. the following:
6.1 Alternative monitoring requirements
may be prescribed when Installation of :l con-
tinuous monitoring system or monttorlng de.
vice speclfted by this Appendix would not pro-
vide accurate determinations of emi:o>slons
(e.g.. condensed. uncombtned water vapor
may prevent an accurate determlna.tlon of
opacity using commercially avallabJ~ con-
tinuous monttorlng systems).
6.2 Alternative monttorlng requirements
may be prescribed when the affected fa('i!ltv
Is Infrequently operated leg. ~ome alfp.C'ted
fa.cUtttes may operate less than one month
per year).
6.3 Alternattve monttortng requirements
may be prescribed when the State determlnps
that the requirements of this Appendix .,.ould
tmpose an extreme economic burden Qn the
source owner or operator
6.4 Alternative monitoring requirements
may be prescrtbed when the State de'.prmlnes
that monltortng systems prescribed bv thts
Appendix cannot be Installed due to ph.,.<;ical
limitations at the factllty
I FR Doc 75-26566 Filed 10-3-75.8.45 3m \
FEDERAL REGISTER. VOL. 40. NO. 194-MONDAY, OCTOBER 6. 1975
59
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16250
IFRL 423-7)
PART 6G--STANDARDS OF PERFORM.
ANCE FOR NEW STATIONARY SOURCES
Emission Monitoring Requirements and
Revisions to Performance Testing
Methods
On September 11. 1974139 FR 328521,
the Environmental Protection Agency
( EP A I proposed revISions to 40 CFR Part
60, Standards of Performance for New
StatIOnary Sources, to establish specific
reqwrements pertammg to continuous
emISSIon monitormg system performance
specifications, operating procedures. data
These requirements would apply to new
and modified facilities covered under
Part 60, but would not apply to existing
facihties.
Simultaneously (39 FR 32871). the
Agency proposed revisions to 40 CFR
Pnrt 51, Requirements for the Prepara-
tIon. Adoption, and Submittal of Imple-
mentatIOn Plans, which would require
States to revise their State Implementa-
tion Plans. (SIP'S) to include legal en-
forceable procedures requirmg certain
specified stationary sources to monitor
emIssions on a continuous basis. These
requIrements would apply to existing fa-
cilities, which are not covered under Part
60.
Interested parties particIpated in the
rulemakin&-bY sending comments to EPA.
A total of 105 comment letters were re-
ceived on the proposed revisions to Part
60 from monitoring equipment manulac-
turers, data processmg equipment manu-
Cacturer,. industrial users of monitoring
equIpment. air poUutlOn control agencies
mcludm!! State, local. and EPA regional
Omces. other Federal agencies, and con-
sultants. Copies of the comment letters
receIved and a ,ummary of the issues and
EPA's responses are available for inspec-
tion and copying at the U.S. Environ-
mental Protection Agency. Public Infor-
matIOn Reference Urnt. Room 2922 (EPA
Library " 401 M Street, S.W.. Washing-
ton. D.C. In addition, copies of the issue
,ummary and EPA responses may be ob-
tained upon wrItten request from the
EPA Public Information Center IPM-
215'. 401 M Street, S.W.. Washington.
D.C. 20460 (specify Public Comment
Summary: EmissIOn Monitoring RequIre-
ments). The comments have been care-
fuUy considered. additional information
has been cpUected and assessed, and
where determined by the Administrator
to be appropriate, changes have been
made to the proposed regulations. These
chan1:es are Incorporated 10 the regula-
tion.; promulgated herein.
BACKGIIOUND
A the time the regulations were pro-
pos, 1 September 11, 1974), EPA had
pro". ,lgated 12 standards of perform-
ance or new stationary sources under
'ectlon III of the Clean Air Act. as
amended, four of which required the af-
fected faCilities to install and operate
,vst..ms which contmuously mom tor the
I. \..1> <>f pollutant emissions. where the
tel'lllJlt'al feasIbility eXIst, USlI1tt cur-
rent1~. .1V:ulable continuous monitoring
technology. and where the cost of the
RULES AND REGULATIONS
systems is reasonable. When the four
standards that require monitoring sys-
tems were promulgated. EPA hadJimited
knowledge about the operation of such
systems because only a few systems had
been installed: thus, the requirements
were specified in general terms. EPA
initiated a proiram to develop perform-
ance specifications and obtain informa-
tion on the operation of continuous
monitoring Systems. The program was
designed to assess the systems' accuracy.
reliability, costs, and problems related
to installation, operation. maintenance,
and data handling. The proposed regu-
lations (39 FR 32852) were based on the
results of this program.
The purpose of regulations promul-
gated herein is to establish minimum
performance specifications for cdntlnu-
ous monitoring sYstems, minimum data
reduction requirements, operating pro-
cedures. and reporting requirements for
those affected facilities required to In-
staU continuous monitoring systems.
The specifications and procedures are
designed to assure that the data obtained
from continuous monitoring systems will
be accurate and reliable and provide the
necessary Information for determining
whether an owner or operator is follow-
Ini proper operation and maintenance
procedures.
SIGNIFICANT COMMENTS AND CHANGES
MADE To PROPOSED REGULATIONS
Many of the coinment letters received
by EPA contained multiple comments.
The most signlncant comments and the
differences. between the proposed and
final regulations are discussed below.
(1) Subpart A-General Provisions.
The greatest number of comments re-
ceived pertained to the methodology and
expense of obtaining and reporting con-
tinuous monitoring system emission
data. Both air pollution control agencies
and a!Tected users of monitoring equip-
ment presented the view that the pro-
posed regulations requiring that all
emission data be reported were exces-
sive, and that reports of only excess
emissions and retention of all the data for
two years on the a!Tected facility's
premises is sut!lcient. Twenty-five com-
mentators suggested that the e!Tective-
ness of the operation and maintenance of
an a!Tected facility and its air pollution
control system could be determined by
reporting only excess emissions. Fifteen
others recommended deleting the repOrt-
109 requirements entirely.
EPA has reviewed these comments and
has contacted vendors of monitoring and
.data acquisition equipment for addi-
tional mformatlon to more fully assess
the impact of the proposed reporting
requirements. Consideration was also
given to the resources that would be re-
quired of i:PA to enforce the proposed
requirement. the costs that would be
incurred by an affected source, and the
effectiveness of the proposed require-
ment in comparison with a requirement
to report only excess emissions. EPA
concluded that reportmg only excess
emissIons would assure proper operation
and mamtenance of the air poUutlon
control equipment and would result in
lower costs to the source :lnd allow more
e!Tective use of EPA resources by elimi-
nating the need for handling and stor-
ing lal'ge amounts of data. Therefore,
the regulation promulgated herein re-
quires ownl!rs or operators to report onlY
excess emissions and to maintain a
permanent record of all emission data
for a period of two years.
In addition, the proposed specification
of minimum data reduction procedures
has been changed. Rather than requiring
Intel!Tated averages as proposed, the reg-
ulations promulgated herein also spec-
ify a method by which a minimum num-
ber of data points may be used to com-
pute average emission rates. For exam-
ple, average opacity emissions over a six-
minute period may be calculated from a
minimum of 24 data points equally
spaced over each six-minute period. Any
number of equally spaced data points in
excess of 24 or continuously Integrated
data may also be used to compute slx-
minute averages. This specification of
minimum computation requirement.~
combined with the requirement to report
only excess emissions provides source
owners and operators with maximum
flexibility to select from a wide cRoice of
optional data reduction procedures.
Sources which monitor only opacity and
which infrequently experience excess
emissions may choose to utilize strip
chart recorders. with or without contin-
uous six-minute Intel!Tators: whereas
sources monitoring two or more pollut-
ants pius other parameters necessary to
convert to units of the emission stand-
ard may choose to utilize existing com-
puters or electronic data proces&,es in-
corporated with the monitoring system.
All data must be retained for two years,
but only excess emissions need be re-
duced to units of the standard. However.
m order to report excess emissions. ade-
quate procedures must be utilized to in-
sure that excess emissions are identified.
Here again, certain sources with minimal
excess emissions can determme excess
emissions by review of strip charts, while
sources with varying emission and ex-
cess air rates will most likely need to
reduce all data to units of the standard to
identify any excess emissions. The regu-
lations promulgated herein allow the use
of extractive. gaseous monitoring systems
on a time sharing basis by installing sam-
pling probes at several locations. provIded
the minimum number of data points
f four per hour) are obtained.
Several commentators stated that the
averatting periods for reduction of monl-
tonng data. especiaUy opacity. were too
short and would result in an excessIve
amount of data that must be~educed and
recorded. EPA evaluated these comments
and concluded that to be useful to source
owners and operators as \\'1'11 as enforce-
ment agencies, the averaging time for the
continuous monitoring data st.ould be
reasonably consistent with the averag-
ing time for the reference methods used
during pf'rformancf' test,. The data re-
duction rcquirement.~ for opanty han'
been substantially reduced because the
averaging period \\'as changed from one
FEDERAL REGISTER, VOL. '40, NO. I 94-MONDAY. OCTOSER 6, 1975
60
-------
minute. which wa.~ proposed. to six mm-
utes to be consIStent with revisions made
to Method 9 (39 FR 39872'
Numerous comments were received on
proposed f 60.13 which resulted In several
changes. The proposed section has been
reorganized and revised in several re-
spects to accommodate the comments
and provide clarity, to more specifically
delineate the equipment subject to Per-
formance Specifications in Appendix B.
and to more specifically define require-
ments for equipment purchased prior to
September 11. 1974. The provisions in
f 80.13 are not intended to prevent the
use of any equipment that can be demon-
strated to be reliable and accurate;
therefore. the performance of monitor-
ing systems Is specified In general terms
with minimal references to specific equip-
ment types. The provisions in ~ 60.13m
are included to allow owners or operators
and equipment vendors to apply to the
Administrator for approval to use alter-
native equipment or procedures when
equipment capable of producing accurate
results may not be commercially avail-
able le.g. condensed water vapor Inter-
feres with measurement of opacity>,
when unusual circumstances may justify
less costly procedures, or when the owner
or operator or equipment vendor may
simply prefer to use other equipment or
procedures that are consistent with his
current practices.
Several paragraphs in' ~ 60.13 have
been changed on the basis of the com-
ments received. In response to comments
that the monitor operating frequency're-
qulrements did not consider periods when
the monitor is Inoperative or undergo-
Ing maintenance, calibration, and adJust-
ment. the operating frequency require-
ments have been changed. Also the fre-
quency of cycling requirement for opacity
monitors has been changed to be con-
sistent with the response time require-
ment m Performance Specification I,
.vhich refiects the capability of commer-
cially available equipment.
A second area that received comment
concerns maintenance performed upon
continuous monitoring systems. Six
commentators noted that the proposed
regulation requiring extensive retesting
of continuous monitoring systems for all
minor failures would discourage proper
mamtenance of the systems. Two other
commentators noted the difflculty of de-
termining a general list of critical com-
ponents. the replacement of which would
automatically require a retest of the sys-
tem. Nevertheless. it is EPA's opinion
that some control must be exercised to
msure that a suitable monitoring system
is not rendered unsuitable by substantial
alteration or a lack of needed mainte-
nance. Accordingly. the regulations pro-.'
mulgated herein require that owners or
operators submit with the quarterly re-
port information on any repairs or,modi-
fications made to the system during the
reporting period. Based upon this infor-
mation. the Administrator may review
the status of the monitoring system with
the owner or operator and. if determined
to be necessary. require retesting of the
continuous mOnitoring system(s).
RULES AND REGULATIONS
Several commentators noted that the
proposed reporting requirements are un-
necessary for affected facilities not re-
quired to Install continuous monitoring
systems. Consequently. the regulations
promulgated herein do not contain the
requirements.
Numerous comments were received
which indicated that some monitoring
systems may not be compatible with the
proposed test procedures and require-
ments. The comments were evaluated
and. where appropriate. the proposed
test procedures and require~ents were
changed. The procedures and require-
ments promulgated herein are applicable
to the majority of acceptable systems;
however. EPA recognizes that there may
be some acceptable systems available
now or in the future which could not
meet the requirements. Because of this.
the regulations promulgated herein in-
clude a provision which allows the Ad-
ministrator to approve alternative testing
procedures. Eleven commentators- noted
that adjustment of the monitoring In-
struments may not be necessary as a re-
sult of daily zero and span checks. Ac-
cordingly. the regulations promulgated
herein require adjustments only when
applicable 24-hour drift limits are ex-
ceeded. Four <;ommentators stated that
It Is not necessary to introduce calibra-
tion gases near the probe tips. EPA has
demonstrated In field evaluations that
this requirement Is necessary In order to
assure accurate results; therefore. the
requirement has been retained. The re-
quirement enables detection of any dilu-
tion or absorption of pollutant gas by the
plumbing and conditioning systems prior
to the pollutant gas entering the gas
analyzer.
Provisions have been added to these
regulations to require that the gas mix-
tures used for the daily calibration check
of extractive continuous monitoring Sys-
tems be traceable to National Bureau of
Standards (NRS> reference gases. Cali-
bration gases used to conduct system
evaluations under Appendix B must
either be analyzed prior to use or shown
to be traceable to NBS materials. This
tra.ceabillty requirement will assure the
accuracy of the calibration gas mixtures
and the comparability of data from sys-
tems at all locations. These traceability
requirements will not be applied when-
ever the NBS materials are not a va.lla.ble.
A list of available NBS Standard Refer-
ence Materials may be obtained from the
Offlce of Standard Reference Materials,
Room B311, Chemistry Building. Na-
tional Bureau of Standards. Washington.
D.C. 20234.
Recertification of the continued ac-
curacy of the calibration gas mixtures is
also necessary and should be performed
at intervals recommended by the cali-
bration gas mixture manufacturer. The
NBS materials and calibration gas mix-
tures traceable to these materials should
not be used after expiration of their
stated shelf-life. Manufacturers of cali-
bration gas mixtures generally use NBS
materials for traceability purposes,
therefore. these amendments to the reg-
Ifi251
ulatton.~ will not Impose additIOnal rc-
quirements upon most manufaclurl'l's
(2) Subpart D-Fossi.l-Fuel FIred
Steam Generators. Eighteen commenta-
tors had questions or remarks concern-
ing the proposed revisions dealing \\'1th
fuel analysis. The eva.luatlOn of these
comments and discussions W1th coal sup-
pliers and electric utility compan:es 1ed
the Agency to conclude that the pro-
posed provisions for fuel ana"sis are not
adequate or consistent with the current
fuel situation. An attempt was made to
revise the proposed provisions; however,
it became apparent that an in-depth
study would be nece1!sary before mean-
ingful provisions could be developed. The
Agency has decided to promulgate all of
the regulations except those dealing with
fuel analysis. The fuel analysis provi-
sions of Subpart D have been reserved
In the regulations promulgated herein.
The Agency has tnitlated a study to ob-
tain the necessary information on the
variability of sulfur content in fuels. and
the capability of fossil fuel fired steam
generators to use fuel analysts and
blending to prevent excess sulfur dioxide
emissions. The results of this study wlli
be used to determine whether fuel anal-
ysis should be allowed as a meB.r1S of
measuring excess emissions. and if al-
lowed, what procedure should be re-
quired. It should be pointed out that
this action does not a.lfect facUities which
use fiue gas desulfurization as a means
of complying with the sulfur dioxide
standard; these facilities are st1ll re-
quired to install continuous emission
monitoring systems for sulfur dioxide.
Facilities which use low sulfur fuel as a
means of complying with the sulfur di-
oxide standard may use a continuous
sulfur dioxide monitor or fuel analysis.
For facilities that elect to use fuel anal-
ysis procedures. fuels are not required
to be sampled or analyzed for prepara-
tion of reports of excess emissions until
the Agency finalizes the procedures and
requirements.
Three commentators recommended
that carbon dioxide continuous mom tor-
ing systems be allowed as an alternative
for oxygen monitoring for measurement
of the amount of diluents in fiue ~ases
from steam generators. The Agency
agrees with this recommendation and has
Included a provision which allows the use
of carbon dioxide monitors. This pro-
vision allows the use of pollutant mom-
tors that produce data on a wet basis
without requiring additional equipment
or procedures for correction of data to a
dry basis. Where CO, or 0, data are not
collected on a consistent basis Iwet or
dry) with the pollutant data, or where
oxygen is measured on a wet basIS. al-
ternative procedures to provide correc-
tions for stack moisture and eXce~ air
must be approved by the Administrator.
Similarly, use of a carbon dioxide con-
tinuous monitoring system downstream
of a fiue gas desulfurizatlOn system IS not
permitted without the Adminlstrator's
prior approval due to the potential for
absorption of CO, within the control
device. It should be noted that when any
fuel is fired directly in the stack gase~
FEDERAL REGISTER, VOL. 40, NO. 194-MONDAY, OCTOBER 6, 1975
61
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162;;2
for reheatmg, the F and F factors
promulgated herein must be prorated
based upon the total heat input of the
fuels fired withm the facility regardless
of the locations of fuel firing, Therefore,
any facility using a flue gas desulfuriza-
tion system may be limited to dry basis
momtormg instrumentation due to the
'restrlctions on use of a CO, diluent moni-
tOr unless water vapor IS also measured
sublect to the Administrator's approval.
Two commentators requested that an
additional factor (F .) be developed for
IIse with mcygen continuous monitoring
systems that measure flue gas diluents on
a wet basIS. A factor of this type was
evaluated by EPA, but is not being pro-
mul~ated with the regulations herein.
The error in the accuracy of the factor
may exceed =5 percent without addi-
tional measurements to correct for va-
natlCJns in flue gas moisture content due
to fluctuations in ambient humidity or
fuel moisture content. However, EPA will
approve mstallation of wet basis oxygen
systems on a case-by-case basis if the
owner or operator will proposed use of
additional measurements and procedures
to control the accuracy of the F. factor
wlthm acceptable limits. Applications for
approval of such systems should include
the frequency and type of additional
measurements proposed and the resulting
accuracy of the Fw facttir under the ex-
tremes of operating conditions
finilcipated
One commentator stated that the pro-
pos",d requirements for recording heat
input are superfluous because this infor-
matIOn Is not n",eded to convert monitor-
Ing data to units of the applicable stand-
ard. EP A has reevaluated this reqUire-
ment and has determined that the con-
versIOn of excess emissIOns into umts of
the standards will be based upon the
F factors and that measurement of the
rates of fuel firing will not be needed ex-
cept when combinations of fuels are fired.
'>'ccordingly, the regulations promulgated
herem require such measurements only
wh('n multiple fuels are fired.
Thirteen commentators questioned the
ratIOnale for the proposed increased op-
erating temperature of the Method 5
sampling train for fossil-fuel-fired steam
generator particulate testmg and the
basl< for raising rather than lo"..enng
the temperature. A brief discussIOn of. the
ra !lonale behind this reVISion was pro-
vided m the preamble to the proposed
regulations, and a more detailed discus-
sion IS provided here. Several factors are
of pnmary importance In developmg the
data base for a standard of performance
and :n speclfymg the reference method
for';.e in conducting a performance test,
mcl 'lng:
a 'he method used for data gathering
to e ablish a standard must be the
sam(' s, or must have a known relation-
ship to, the method subsequently estab-
lished as the.Ieference method,
b The method should measure pollut-
ant ('missions indicative of the perform-
ance of the best systems of emiSSion re-
'1111'!:nn A method meetmg this cntenon
w.ll not necessarily measure emlSSlOTlS
as they would exist after dilution and
RULES AND REGULATIONS
cooling to ambient temperature and pres-
sure, as would occur upon release to the
atmosphere. Ai; such. an emission factor
obtained through use of such a method
would. for example, not necessarily be of
use In an ambient dispersion model. This
seeming inconsistency results from the
fact that standards of performance are
Intended to result in installation of sys-
tems of emission reduction which are
consistent with best demonstrated tech-
nology, considering cost. The Adminis-
trator, in establishing such standards. Is
required to identify best demonstrated
technology and to develop standards
which reflect such technology. In order
for these standards to be meaningful,
and for the required control technology
to be predictable, the compliance meth-
ods must measure emissions which are
indicative of the performance of such
systems.
c, The method should Include sufficient
detail as needed to produce consistent
and reliable test results.
EPA relies primarily upon Method 5
for gathering a consistent data base for
particulate matter standards. Method 5
meets the above ulteria by providing de-
tailed sampling methodology and in-
cludes an out-of-stack filter to facilitate
temperature control. The latter Is needed
to define particulate matter on a com-
mon !jasls since It is a function of tem-
perature and is not an absolute quantity.
If temperature Is not controlled. and/or
If the el'lect of temperature upon particu-
late formation IS unknown, the e/fect on
an emission control limitation for partic-
ulate matter may be variable and un-
predictable.
Although selection of temperature can
be varied from industry to m!lustry. EPA
specifies a nom mal sampling tempera-
ture of. 120' C for most source categories
subject to standards of performance.
Reasons for selection of 120' C Include
the following:
a. Filter temperature must be held
above 100. C at sources where moist gas
streams are present. Below 100' C, con-
densation can occur with resultant plug-
ging of filters and possible gas !liquid re-
actions. A temperature of 120. C allows
for expected temperature variation
within the train, without dropping below
100' C.
b. Matter eXisting in particulate form
at 120. C is indicative of the perform-
ance of the best particulate emission re-
duction systems for most mdustrlal proc-
esses. These Include systems of emission
reduction that may involve not only the
final control device, but also the process
and stack gas conditioning systems.
c. Adherence to one established tem-
perature (even though some variation
may be needed for some source categor.
iI's) allows comparison of emissions from
source category to source category. This
limited standardization used in the de-
velopment of standards of performance
is a benefit to equipment vendors and to
source owners by providing a consistent
basis for comparing test results and pre-
dicting control system performance. In
comparison. in-stack filtration takes
place at stack temperature, which usually
Is not constant from one source to the
next. Since the temperature varies. in-
stack ftltration does not necessarily pro-
vide a consistent definition of particulate
matter and does not allow for compari-
son of vanous systems of control. On
these bases. Method 5 with a sampling
filter temperature controlled at approxi-
mately 120' C was promulgated as the
applicable test method for new fossil-fuel
fired steam generators.
Subsequent to the promulgation of the
standards of performance for steam
generators. data became available indi-
cating that certain combustion products
. which do not exist as particulate matter
at the elevated temperatures existing in
steam genera tor stacks may be collected
by Method 5 at lower temperatures (be-
low 160., C I. Such material. existing in
gaseous form at stack temperature.
would not be controllable by emission re-
ductiQn systems Involving electrostatic
precipitators (ESP). Consequently,
measurement of such condensible matter
would not be indicative of the control
system performance. Studies conducted
In the past two years have confirmed that
~uch condensation can occur. At sources
where fuels containing 0.3 to 0.85 percent
sulfur were burned. the Incremental in-
crease In particulate matter concentra-
tion resulting from ,ampling at 120. C
a~ compared to about 150. C ",as found
to be variable, ranging from 0.001 to
0.008 gr/sef. The variability is not neces-
sarily predictable, since total sulfur oxide
t:oncentration, boiler design and opera-
tion. and fuel addlti\'es each appear to
have a potential e!tect, Based upon these
data. it Is concluded that the potential
increase In particulate concentration at
sources meeting the standard of per-
formance for sulfur oxides Is not-a serl-
nus problem In comparison with the par-
ticulate standard which Is approximately
0.07 gr/scf. Nevertheless, to Insure that
an unusual case wilI not occur where a
high concentration of condensible mat-
ter, not controllable with an ESP. would
prevent attainment of the particulate
standard, the samuling temperature al-
lowed at fossil-fuel fired steam boilers is
being raised to 160. C. Since this tem-
peratur(' Is attainable at new steam gen-
erator stacks. sampling at temperatures
above 160. C would not yield results ncc-
essarily representative of the capabilities
of the best systems of emission reduction.
In evaluatinl<' particulate samplinr::
techniques and the e!tect of sampling
temperature. particular attention has
also been given to the possibility that
SO, may react in the front half of the
Method 5 train to form particulate mat-
ter. Based upon a series of comprehen-
sive tests involving both source and con-
trolled environments. EPA has developed
data that show such reactions do not oc-
t:ur to a significant degree.
Several control agencies commented on
the increase in sampling temperature
and suggested that the need is for sam-
pling at lower, not higher. temperatures.
This is a relevant comment and is one
which must be considered in terms of the
basis upon which standards are estab-
lished.
FEDERAL REGISTER. VOL. 40. NO, 194-MONDAY. OCTonR 6, 1975
62
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For existing boilers which are not sub-
Ject to this standard. the eXistence of
higher stack temperatures and/or the
use of higher sulfur fuels may result in
significant condensation and resultant
high indicated particulate concentra-
tions when sampling is conducted at
120' C. At one coal fired steam generator
burning coal containing approximately
three percent sulfur, EPA measurements
at 120' C showed an increase of 0.05 gr/
dscf over an average of seven runs com-
pared to samples collected at approxi-
mately 150' C. It Is believed that this in-
crease resulted, in large part, if not
totally. from SO, condensation which
would occur also when the stack emis-
siOns are released into the atmosphere.
Therefore. where standards are based
upon emission reduction to achieve am-
bient air quality standards rather than
on control technology (as Is the case
with the standards promulgated herein),
a lower sampling temperature may be
appropriate.
Seven commentators questioned the
need for traversing for oxygen at 12
points within a duct during performance
tests. This requirement. which is being
revised to apply only when particulate
sampling Is performed (no more than 12
points are required) Is included to in-
sure that potential stratification result-
ing from air in-leakage will not ad-
versely affect the accuracy of the
particulate test.
Eight commentators stated that the
requirement for continuous monitoring
of ni trogen oxides should be deleted be-
cause only two air quality control re-
gions have ambient levels of nitrogen
dioxide that exceed the national ambient
air quality standard for nitrogen dioxide.
Standards of performance issued under
section 111 of the Act are designed to re-
qUire affected facilities to design and in-
stall the best systems of emission reduc-
tion (taking into account the cost of such
reduction). Continuous emission mon-
itorlnlt systems are required to insure
that the emission control systems are
operated and maintained properly. Be-
cause of this. the Agency does not feel
that it is appropriate to delete the con-
tinuous emission monitoring system re-
quirements for nitrogen oxides: however,
in evaluating these comments the Agency
found that some situations may exi&t
where the nitrogen oxides monitor Is not
necessary to Insure proper operation
and maintenance. The quantity of nitro-
gen oxides emitted from certain types of
furnaces is considerably below the nitro-
gen oxides emission limitation. The low
emission level Is achieved through the
design of the furnace and does not re-
quire specific operating procedures or
maintenance on a continuous basis to
keep the nitrogen oxides emissions below
the applicable standard. Therefore, in
this situation, a continuous emission
monitoring system for nitrogen oxides Is
unnecessary. The regulations promul-
gated herein do not require continuous
emission monitoring systems for nitrogen
oxides on facilities whose emissions are
30 percent or more below the applicable
standard.
RULES AND REGULATIONS
Three commentators requested that
owners or operators of steam generators
be permitted to use NO, continuous mon-
itoring systems capable of measuring
only nitric oxide < NO) since the amount
of nitrogen dioxide (NO,) in the fiue
gases is comparatively small. The reg-
ulations proposed and those promulgated
herein allow use of such systems or any
system ..meeting all of the requirements
of Performance Specification 2 of Ap-
pendix B. A system that measures only
nitric oxide (NO) may meet these specifi-
cations Including the relative accur&CY
requirement (relative to the reference
method tests which measure NO + NO,)
without modification. However, In the
Interests of maximizing the accuracy of
the system and creating conditions favor-
able to acceptance of such systems (the
cost of systems measuring only NO Is
less), the owner or operator may deter-
mine the proportion of NO, relative to
NO in the fiue gases and use a factor to
adjust the continuous monitoring system
emission data (e.g. 1.03 X NO = NO,)
provided that the factor Is applied not
only to the performance evaluation data,
but also applied comlstently to all data
generated by the continuous monitoring
system thereafter. This procedure Is lim-
Ited to facilities that have less than 10
percent NO, (greater than 90 percent
NO) In order to not seriously Impair the
accuracy of the system due to NO, to NO
proportion fluctuations.
Section 60.45, ron-
ditions of the affected facility '\'Ill 1'1'-
main approximatelY the same as rlurin!!:
the continuous monitoring system I','al-
ua.tlon tests. For sulfuric acid plants th1.'
asswnptlon is Invalid. A sulfuric arid
plant is typically designed to operate at
a constant volumetrtc throt:"hput
(sefm) . Acid production rates are aJt.Prl'rl
by by-passing portions of the proce,s '111'
around the furnace or combustor t,) \'a1"\'
the concentration of the gas enterm>,
the converter. This procedure produc~.'
widely varying amounts of tail gas dilu-
tion relative to the production rate. Ac-
cordingly, EPA has developed new con-
version procedures whereby the a.ppro-
prlate conversion factor is computed
from an ana]ysls of the SO, concentra-
tion entering the converter. Air inJPction
plants must make additional correctIOns
for the diluent air added. Measurement
of the inlet S0, is a normal qualitv con-
tro] procedure used by most sulfuric aCid
plants and does not represent an addi-
tional cost burden. The Reich test or
other suitable procedures may be used.
IS) Subpart J-Petroleum Refinerips.
One commentator stated that n'.e re-
quirements for installation of continuous
monitoring Systems for oxygen and fire-
box temperature are unnecessar:. and
that installation of a fiame detection de-
vice would be superior for proceS3 con-
trol purposes. Also, EPA has obtamed
data which show no identifiable rpJa-
tlonship between furnace temperature.
percent oxygen In the flue gas. and car-
bon monoxide emissions when the facil-
ity is operated in compliance wah the
appl1cable standard. Since flrebox tem-
perature and oxygen measurement., mav
not be preferred by source owners and
operators for process control. and no
FEDERAL REGISTER, VOL. 40, NO. 194-MONDAY, OCTOBER 6, 1975
63
-------
16254
known method is available for transla-
tion of these measurements into quantI-
tative reports of excess carbon monoxide
!'rruSSlOns. this requirement appears to
be of little use to the af'lected facUlties
or Ii) EPA. Accordingly. reqwrements for
Imt.allation of continuous monitoring
wql'ms for measurements of firebox
temperature and oxygen are deleted from
the regulations.
Since EPA has not yet developed per-
formance specifica.tions for carbon mon-
oxide or hydrogen sulfide continuous
momtoring systems. the type' of equip-
ment that may be installed by an owner
or operator in compliance with EPA re-
quirements Is undefined. Without con-
ductmg performance evalua.tions of such
equipment. little reliance can be placed
11pon the value of any data such systems
would generate. Therefore. the sections
of the rl'guJation requiring these systems
are being resl'rved until EPA proposes
performance specificatIOns applicable to
HS and CO monitoring systems. The
pronsions of f 60.105(30) (3) do not apply
to an owner or operator electing to moni-
t.or H,S. In that case. an H.B mom tor
should not be Installed until specific HS
mOl1ltormg requirements are promuI-
gatl'd. At the time specifications are pro-
posl'd. all owners or operators who havl'
not I'nterl'd into binding contractual ob-
ligations to purchase continuous moni-
tonng equIpment by fdate of publication I
WIlJ be required to install a carbon
monoxide continuous monitoring system
and a hydrogen sulfide continuous monl-
tonnl{ system I unless a sulfur dioxide
contmuous monitoring system has been
il'stalJed 1 as applicable.
Section 60 105'aI(2). which specifi~s
thl' I'xcess emissions for capacity that
must be reported. has been reserved for
the same reasons discussed under fossil
fUI'I-flred steam gl'nerators.
'6' Appendix B--Performance SpecI-
fications. A large number of comments
WHe received in reference to specific
tl'chnical and editorial changes needed
In the specIfications. Each of these com-
ml'nts has been reviewed and several
changes m format and procedures have
bl'en made. These include adding align-
ment procedures for opacity morutors
and morl' specific instructions for select-
Inl{ :J. location for Installing the monitor-
Ing equipment. Span requIrements have
!)"en specified so that commercially pro-
duced equipment may be standardized
where possIble. The format of the speci-
ficatlons was sImplified by redl'flninJ;: the
requIrements m terms of percent opacity.
or 0"n:en. or carbon dioxide. or percl'nt
of ,';Jan. The proposed requIrements were
in . ~rms of percent of the I'mission
sta ard which IS less convenient or too
"a~ Eince reference to the emIssion
q', I \l'ds would. have rl'presl'nted a
ran:::. of pollutant concentrations de-
pendwg upon the amount of dilul'nts (i.e.
excess air and water vapor) that are
pre'l'nt in the enluent. In order to cali-
braTe gaseous monitors m terms of a
'penflc concl'ntration. the rl'quirements
wel ~ fl'VIsed to dell'te reference to the
I'ml,SIOn standards.
Four commentators noted that the ref-
erer:ce methods used to evaluate con-
RULES AND REGULATIONS
tinuous monitoring system performance
may be less accurate than the systems
themselves. Five other commentators
questioned the need for 27 nitrogen ox-
ides reference method tests. The ac-
curacy specification for gaseous monitor-
ing systems was specified at 20 percent. a
,'alue in excess of the actual accuracy
of monitoring systems that provides tol-
erance for reference method inaccuracy.
Commercially available monitoring
equipment has been evaluated using these
procedures and the combined errors (i.e.
relative accuracy) in the reference meth-
ods and the monitoring systems have
been shown not to exceed 20 percent after
the data are averaged by the specified
procedures.
Twenty commentators noted that the
cost estimates contained In the proposal
did not fully reftect installation costs.
data reduction and recording costs. and
the costs of evaluating the continuous
monitoring systems. AJ5 a result. EPA
reevaluated the cost analysis. For opac-
ity monitoring alone. investment costs
including data reduction equipment and
performance tests are approximately
520.000. and annual operating costs are
approxfmately $8.500. The same location
on the stack used for conducting per-
formance tests with Reference Method 5
I particulate) may be used by installing
a. separate set of ports for the monitoring
system so that no additional expense for
access is required. For power plants that
are required to install opacity. nitrogen
oxides. sulfur dioxide. and diluent (0,
or CO,) monitoring systems. the invest-
ment cost is approximately $55.000. and
the operating cost IS approximately $30.-
000. These are significant costs but are
not unreasonable in comparison to the
approximately seven million dollar In-
vestment cost for the smallest steam
generation facility alfected by these regu-
lations.
E tJective date. These regula tions are
promulgated under the authority of sec-
tions 111. 114 and 301130) of the Clean
AII' Act as amended [42 U.S.C. 1857c-6.
1857c-9. and 1857g(a) ] and become ef-
fective October 6. 1975.
Dated: September 23. 1975.
JOHN QUARLES.
Acting Administrator.
40 CFR Part 60 is amended by revising
Subparts A. D. F. G. H. I. J. L. M. and O.
and adding Appendix B as follows:
1. The table of sections is amended by
revising Subpart A and adding Appen-
dix Bu follows:
Subp. rt A--Oen..... Provision.
60.13 Monltortng requirements
APPENDIX _PERFORMANt"E SPECIFICATIONS
Performance Specification i-Performance
speclftcat10ns and spectftcatlon teat proce~
dures for transmlssometer systems for can.
tinuous measurement of the opacity of stack
emissions
Performance Specification 2-Performance
speciftcatlons and specU'l.t'at1on test proce-
dures for monitors of 50. and NO from
stationary sources. - ,
Performance SpecUicat10n 3--Performance
specifications and specification test proce-
dure. for monitors of CO. .nd 0, tram sta-
tionary sources. -
Subpart A--General Provisions
Section 60.2 Is amended by revising
paragraph (1') and by adding paragraphs
IX). (y), and IZ) as follows:
Ii 60.2 Definition..
(1') "One-hour period" means any 60
minute period cOmmencing on the
hour.
(x) "Six-minute period" means any
one of the 10 equal parts of a one-hour
period.
(yl "Continuous monitoring system"
means the total equipment. required
under the emission monitoring sections
in applicable subparts. used to sample
and condition (If applicable). to analyze.
and to provide a permanent record of
emissions or process parameters.
(z) "Monitoring device" means the
total equipment. required under the
monitoring of operatIons sectlon.~ in ap-
plicable subparts. used to measure and
record (if applicable) proc~s param-
eters.
3. In f 60.7. paragraph (a) (5) is added
and paragraphs (b). (C). and (d) are
revised. The added and revised provisions
read as follows:
!i (.0.7
Nolifiration and rrcord k..epin..
(3,) . . .
(5) A notification of the date upon
which demonstration of the continuous
mQnitoring system performance com-.
mences in accordance with '60.13tc)
Notification shall be postmarked not less
than 30 days prior to such date.
(b 1 Any owner or operator subject to
the provisions of this part shall mam-
tain records of the occurrence and dura-
tion of af1¥ startuP. shutdown. or mal-
function in the operation of an af'lected
facility: any malfunction of the all' pol-
lution control equipment: or any periods
during which a continuous monitoring
system or monitoring device is inopera-
tive.
(c) Each owner or operator re$luired
to install a continuous monitoring sys-
tem shall submit a written report of
excess emissions' as defined in applicable
subparts) to the Administrator for every
calendar quarter. All quarterly report.,
shall be postmarked by the 30th day fol-
lowing the end of each call'ndar quarter
and shall include the following informa-
tion:
11) 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.
(2) Specific identification of each
period of excess emissions that occurs
during startups. shutdowns. and mal-
functions of the af'lected facIlity. The
nature and cause of any malfunction' if
known). the corrective action taken or
preventative measures adopted.
FEDERAL REGISTER. YOLo 40, NO. 194-MONOAY. OCTO In 6. 1975
64
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RULES AND REGULATIONS
(3J The date and time identifying each ance specification of Appendix B as
period during which the continuous follows:
monitoring system was Inoperative ex- (i) Continuous monitoring systems for
cept for zero and span checks and the measuring opacity of emissions shall
nature of tre system repairs or adjust- comply with Performance Specification l.
ments. Owners or operators of all con-
(2) For continuous monitoring sys- tlnuous monitoring systems installed on
tems referenced In paragraph (c\'(2) of an alfected f1lC1l1ty prior to r date of pro-
this section. completion of seven days of mulgationJ are not required to conduct
operation. tests under paragraphs (c) (2) (j) and/or
(3) For monitoring devices referenced (Ii) of this section unJess requested by
in applicable subparts. completion of the the Adtn1n1strator.
manufacturer's written requirements or (3) AJI continuous monitoring systems
recommendations for checking the op- referenced by paragraph (c) (2) of this
eration or cal1bration of the device. section shall be upgraded or replaced (If
(c) During any performance tests necessary) with new continuous monl-
required under ~ 60.8 or within 30 days toring systems. and such Improved sys-
thereafter and at such other times as tems shall be demonstrated to comply
may be required by the Administrator with appl1ca.ble performance speclfica-
under section 114 of the Act. the owner tions under paragraph (c) <1) of this
or operator of any alfected facility shall section by September 11. 1979.
conduct continuous monitoring system (d) OWners or operators of all con-
performance evaluations and furnish the tlnuous monitoring systems Installed in
Administrator within 60 days thereof two accordance with the provisions of this
or, upon request. more copies of a written part shall check the zero and span drift
report of the results of such tests. These at least once dally In accordance with
continuous monitoring system perform- the method prescribed by the manufac-
ance evaluations shall be conducted in turer of such systems unless the manu-
accordance with the following specifica- facturer recommends adjustments at
tlons and procedures: shorter Intervals. In which case such
(1) Continuous monitoring systems recommendations shall be followed. The
I1sted within this paragraph except as zero and span shall. as a minimum. be
provided in paragraph (c) (2) of this sec- adjusted whenever the 24-hour zero drift
tlon shall be evaluated In accordance or 24-hour calibration drift limits of the
with the requirements and procedures appl1cable performance specifications In
contained in the applicable perform- Appendix B are exceeded. For continuous
-l6255
monitormg systems measuring opaCIty of
emissions, the optical surfaces exposed
to the effluent gases shall be cleaned prior
to performing the zero or span dnft ::u:I-
justments except that for systcl11' usm~
automatic zero adjustments. the optical
surfaces shall be cleaned when the cwn-
ulatlve automatic zero compensatIOn ex-
ceeds four percent opacity. UnJess other-
wise approved by the Administrator. the
following procedures. as applica.ble, shall
be followed:
<1) For extractive continuous moni-
toring systems measuring gases. minJ-
mum procedures shall Include introduc-
ing applicable zero and span gas mixtures
into the measurement system as near the
probe as Is pr1lCtical. Span and zero gases
certified by their manufacturer to be
traceable to National Bureau of Stand-
ards reference gases shall be used when-
ever these reference gases are available.
The span and zero gas mixtures shall be
the same composition as specified in Ap-
pencUx B of this part. Every six months
from date of manufacture. span and zero
gases shall be reanalyzed by conducting
triplicate analyses with Reference Meth-
ods 6 for SO,. 7 for NO., and 3 for 0,
and co,. respectively. The gases may be
analyzed at less frequent Inte1"\'aIs If
longer shelf lives are guaranteed by the
manufacturer.
(2) For non-extractive continuous
monitoring systems measuring gases.
minimum procedures shall Include up-
scale check (s) using a certified calibra-
tion gas cell or test cell which is func-
tionally equivalent to a known gas con-
centration. The zero check may be per-
formed by computing the zero value from
upscale measurements or by mechani-
cally producing a zero condition.
(3) For continuous monitoring systems
measuring opacity of emissions. mini-
mum procedures shall Include a method
for producing a simulated zero opacity
condition and an upscale (span) opacity
condition using a certified neutral den-
sity filter or other related technique to
produce a known obscuration of the lif:ht
beam. Such procedures shall provide a
system check of the analyzer Internal
optical surfaces and all electronic cir-
cuitry Including the lamp and photo<1e-
tector assembly.
Ie) Except for system breakdowns. re-
pairs. calibration checks. and zero and
span adjustments required under para-
graph (d) of this section. all continuous
monitoring systems shall be in contm-
uous operation and shall meet ITUmmum
frequency of operation requirements as
follows:
(1) All continuous monitoring systems
referenced by paragraphs (c' t 1, and
(2) of this section for measuring opacity
of emissions shall complete a minimum of
one cycle of operation (sampling ana-
lyzing. and data recording) for each suc-
cessive 10-second period.
(2) All continuous monitormg systems
referenced by par:fgraph t C) (I' of thlS
section for measuring oxides of nitrogen.
sulfur dloxlde, carbon dioxIde. or oxv'gen
shall complete a minimum of one ~::cle
of operation 'sampling. analyzing. and
data. recording) for pach successive 15-
mmute period.
FEDERAL REGISTER, VOL. 40, NO. 194-MONDAY, OCTOBER 6, 1975
65
-------
16256
'3 I All continuous monitoring systems
referenced by paragraph IC) (2) of this
sectIon. except opacity. shall complete a
minImum of one cycle of operation Isam-
plmg. analyzing. and data recording)
for each succeSSl ve one-hour period.
, f, All continuous monitoring systems
()r monitoring devices shall be installed
such that representative measurements
of emL
-------
or operator except for any affected facil-
ity demonstrated during performance
tests under ~ 60.8 to emit nitrogen oxides
pollutants at levels 30 percent or more
below applicable standards under ~ 60.44
of this part. The following procedures
shall be used for determining the span
and for calibrating nitrogen oxides con-
tinuous monitoring Systems:
(1) The span value shall be determined
as follows:
(I) For affected facilities firing gaseous
fossil fuel ttie span value shall be 500
ppm nitrogen oxides.
<11) For atlected fac1l1t1es firing liquid
fossil fuel the span value shall be 500
ppm nitrogen oxides.
(111) For atlected fac1l1t1es firing solid
fossil fuel the span value shall be 1000
ppm nitrogen oxides.
-------
.Ui2:18
gen oxides are defined as any three-hour
~en~d during which the average emis-
'Ions, arithmetic average of three con-
tiguous one-hour periods) exceed the ap-
pl1cable standards ander I 60.44.
7 Section 60.46 is revised to read as
follows:
fi 60.~6 Test methods and p.....,edure..
I a' The reference methods in Appen-
dix A of this part, except as provided In
I 60.8Ib). shaD be used to determine com-
pliance with the standards as prescribed
In H 60.42. 60.43. and 60.t4 as follows:
I I' Method 1 for selection of sampling
site and sample traverses.
'2' Method 3 for gas analysis to be
used when apPIYmg Reference Methods
5.6 ami 7.
'3 I Method 5 for concentration of par-
ticulate matter and the a.~soclated mois-
ture content.
'4' Method 6 for concentration of SO:.
and
, 5' Method 7 for concentration of
NO,
I b' For Method 5, Method 1 shaIJ be
used to select the sampllnB site and the
number of traverse sampling points. The
sampling time for each run shall be at
l~ast 60 minutes and the minimum sam-
pling volume shall be 0.85 dscm (30 dsct)
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 180' C
'320' F).
'c' For Methods 8 and 7, the sampling
si te shall be the same as that selected
for Method 5. The sampling point In the
duct shall be at the eentrold of the cross
section or at a point no closer to the
walls than 1 m (3.28 ft). For Method 8.
the sample shall be extracted at a rate
proportional to the gas velocity at the
,ampling point.
Id I For Method 8. the minimum sam-
pling time shall be 20 minutes and the
mimmum :;ampling volume 0.02 dscm
10.71 dsct) 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 :\!ethod 7, each run shaD 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 Cal (3), (4), and
151 of this section, the emissions ex-
pre,'ed In g/million cal tib/mi1l10n Btu)
sha. be determined by the following
pro lure'
E=CF( 20.9 )
20.9- ":,0,
where.
II) E = pollutant emissIon g/millIon cal
lib million Btu)
,2) C = pollut2nt concentration. g/dacm
II b dscf\, determined by ~. The conversion fac-
tor shall be determined. as a minimum
three times dally by measuring the con~
centratlon of sulfur dioxide entering the
converter using suitable methods (e.g.,
the Reich test, National Air Pollution
Control Administration Publication No.
999-AP-13 and calculating the appro-
priate conversion factor for each elght-
hour period as follows:
CF =k [1.000-0.01.,;r]
r-s
FEDERAL REGISTER, VOL. 40, NO. I94-MONDAV, OCTOBER 6, 1975
68
-------
where:
CP = conversion factor (kg/metric ton per
ppm. Ib/short ton per ppm) .
k =constant derived from material bal-
ance. For determining CF in metric
units. k =0.0653. Por determining CP
In English units. k=0.1306.
r = percentage of sulfur dioxide by vol-
ume entering the gas converter. Ap-
propriate correctIons must be made
ror air Injection plants subject to the
Admlnlstrator's approval.
s = percentage or sulfur dioxide by vol-
ume In the emissions to the atmos-
phere determined by the continuous
monitoring system required under
paragraph (a) of this section.
(c) The owner or operator shall re-
cord all conversion factors and values un-
der paragraph (b) of thL> section from
which they were computed (i.e.. CF. r.
and s).
( e I For the purpose of reports under
! 60.7 (c J. periods of excess emissions.
shall be all three-hour periods (or the
arithmetic average of three consecutive
one-hour periods) during which the In-
tegrated average sulfur dioxide emissions
exceed the applicable standards under
! 60.82. .
Subpart I-Standards of Performance for
Asphalt Concrete Plants
~ 60.92 [Amcnd..d]
13. Paragraph (a) (2) of ~ 60.92 is
amended by del~ting the second sentence.
Subpart J-Standards of Performance for
Petroleum Refineries
~ 60.102 [Amended]
14. Paragraph (a) (2) of ~ 60.102 Is
amended by del~tlng the second sentence.
15. Section 60.105 Is amended by re-
vising paragraphs (a). (b). and (e) to
read as follows:
~ ('O.105 Emission monitoring.
, a) Continuous monitoring systems
shall be installed. calibrated. maintained.
and operated by the owner or operator as
fo!Jows'
( 1) A continuous monitoring system
for the measurement of the opacity of
emi"ions discharged into the atmosphere
from the ftuld catalytic cracking unit cat-
alyst regenerator. The continuous moni-
toring system shall be spanned at 60. 70.
01' 80 percent opacity.
12) I R~erved]
(3) A continuous monitoring system
for the measurement of sulfur dioxide In
the ga~es discharged into the atmosphere
from the combustion of fuel gases I ex-
cept where a continuous monitoring sYS-
tem for the measurement of. hydrogen
sulfide IS insta!Jed under paragraph (a)
(4) of this section). The po!Jutant gas
used to prepare calibration gas mixturps
under paragraph 2.1. Performance Speci-
fication 2 and for calibration checks un-
der ! 60.13(d) to this part. shall be sul-
fur dioxide ISO,). The span shall be set
at 100 ppm. For conducting monitoring
~ystem performance evaluations under
~ 60.13 (c). Reference Method 6 shall be
used.
RULES AND REGULATIONS
(4) [Reserved]
(b) [Reserved]
(e) For the purpose of reports under
! 60.7 (C) . periods of excess emissions that
sh&!J be reported are defined as fo!Jows:
(1) [Reserved]
( 2) [ Reserved]
(3) rR~ervedJ
(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.
Subpart L-Standards of Performance for
Secondary Lead Smelters
~ 60.122 [Amended]
16. Section 60.122 Is amended by de-
leting paragraph (~).
Subpart M-Standards of Performance for
Secondary Brass and Bronze Ingot Pro-
duction Plants
~ 60.132 [Amended]
17. Section 80.132 Is amended by de-
leting paragraph (c).
Subpart ~Standards of Performance for
Sewage Treatment Plants
~ 60.152 [Amended]
18. Paragraph (a) (2) of ~ 60.152 Is
amended by deleting the second sentence.
19. Part 60 is amended by adding Ap-
pendix B as follows:
APPENDIX B-PERFoKMANCE SPECIFICATIONS
Performa.nce Specification I-Performance
specificatIons a.nd speClfication test proce..
dures tor tran3mLssometer systems for con-
tinuous monitoring system exceed the emis..
slons
I. Principle and Appllca.bUlty.
I I Principle. The opacity or particulate
matter 1n stack emissions 1.9 measured by a
continuously operating emissIon measure.
ment system. These systems are based upon
the principle ot transmt~ometry which is a
direct measurement of the attenuation of
visible radiation (opacity) by particulate
matter in a stack effluent. Light having spe..
cftc spectral characterLstics 15 projected trom
a lamp across the stack or a pollutant source
to a llght sensor. The llght Is attenuated due
to absorption and scatter by the particulate
matter in the effluent, The percentage of
visible. light attenuated Is defined as the
cpactty of the emission. Transparent stack
emissions that do not attenuate light will
have a transmittance of 100 or an opacity of
O. Opaque stack emissions that attenuate all
of the visible light will have a transmittance
of 0 or an opacity of 100 percent- The trans-
m1ssometer i5 - evaluated by use of neutral
density filters to determlne the precist::m of
the continuous monitoring system Tests of
the system are performed to determtne zero
drift. callbratlon drift, and response time
characteristics of the system,
1.2 Appllcablllty. This performance spe-
Clfica.tlon Is aiJpl1cable to the continuous
monitoring systems specified In the subparts
for measuring opacity cf emissions SpeCifi-
cations for continuous measurement 0: vis.
Ible emissions are given In terms of design.
~6259
perfonnance. and insta1la.tton pa.ra.meters
These specifications contain test procedures,
installa.t1on requirements. and data compu-
tation procedures for evaluating the accept.
ability of the continuous monitoring sy~tems
subject to approval by the Administrator
2 Apparatus.
2 I Calibrated Filters. Optical fiIters with
neutra.l spectra.l characteristics and known
0l?tlca.l densit1ps to visible l1~ht or 5Crf"enS
known to produce specified optical d{,I1~lt le:->
C&llbra.ted filters with accuracies certlncd b\'
the manufacturer to with1n -=3 pf.'rcent
opacity sh..ll be used. Filters required Me
low. mid. and high-rang" filters with nom-
Inal optical den.ltles as follows when the
transmlssometer i8 spanned at opacity levels
specified by applicable subparts.
Span valu,"
(pereent or>o.ctty)
CallhrRted ftltl'r optiral rl""r,sl!\I'!'
with ('Qu1~al{>n' OP:J.('Hy In
pn.rcnrh('sts
Low~
ra.nlZE"
~lId-
rnn~p
Hich.
nn,.'('
----
50.
00.
70.
80 .....
00..
100.
0.1 t!Ol
.1 (20)
I (20\
I (~o)
I (201
.1 (Wj
0.2 f3';')
.2 (37)
,3 1-",0)
.3 (50)
~ -\ It'll)
.. (rJO)
() 3 .')0,
.:\ '.\(1)
.\ 11.1)1
I; 1'';'',1
- ,"'-II)
J f ~71 ",I
It Is recommended tha.t fil ter caUbra tlons
be checked with .. well-collimated photopic
transmissometer of known Hnearlty pr10r to
use. The filters shall be or sufficIent size
to attenuate the enUre Hght beam of the
transm1<;someter
22. D..ta Recorder. Analog chart recorder
or other suitable device with Input voltage
range compatlb~e with the o.nalyzer system
output. The resolution or the I't'ccroer's
data output shall be sumclent to allo',\' com-
pletion of the test procedure, withIn thIs
specification.
2.3 Opacity measurement System. An In-
stack transm1ssome1:..er (folded or single
path) with the optical design specifications
destgnated below, associated control units
and appBratu; to keep opttcal surraceo:; ('lean
3. Dellnltlons.
3.1 Continuous Monlto!'1ng System The
total equipment requtred for the determina-
tion of pollutant opacity tn a source effi'.lent.
Continuous _monItorlnR; systems con.5Lo,t of
major subsystems as follows:
3.1.1 SampHng Interrace. The portion or a
continuous m:Jnttorll1g "ystem for ,-,pa"ltv
that protects the analyzer from the- effluent.
3.1.2 Analyzer That portion or the con-
ttnuous monltorlng system whIch senses ~he
pollutant and generates a signal ouq)ut "hat
i5 a runctlOO1 of the pollutant opaclt';"
3.1.3 Data Recorder. That part Ion of 'he
continuous monitoring svstem that pr,-Jcesses
the ana.lyzer output and provide:; a pE"T.r::na.
nent record of the output ~ignal In terms of
pollutant opacity.
3 2 Transmlssometer. The portions of a
cont1nunus monitoring system for v'):,\CI ty
that include the sampl1ng tnterfJ.ce ,"UI
-------
16260
'):hen the pollutant concentrat10n at the
:Ime of the measurements 11 zero
3.6 Callbratlon Drtft. The change In the
continuous monitoring system output over
a. sta.t~ peT'tod of t1me of norm3J continuous
operatIon when the pollutant concentration
at the t1me of the measurements 13 the sa.me
known up,.,..le value.
37 System Reaponse. The time Interval
from a step change In opacity In the stack
at the Input to the continuous monitoring
system to the time at which 95 percent of
the corresponding final v-al ue Is reached as
dlsplayed on the continuous monitoring ay.-
tern data Te'Corder.
38 Oper..tlonal Test Period. A m1nlmum
period of time over which a contlnuou.
monl tortng syatem 18 expected to operate
wi thin certain pe1'formance apecllicatlona
without unscheduled m&lntenance. Tepalr,
or adJuatme'1it.
3.9 Transmittance. The fnctlon of Incident
light that. Is transmitted through an optical
medium of Intereat.
3.10 Opacity. The fraction of Incident llght
that \3 attenuated by an optical medium of
Interest. Opacity (0) a.nd transmittance (T)
are related as followa:
O=I-T
3.11 Optical Density. A logarithmic meu-
ure of the amount of llght that It attenuated
by an optical medium of Interest. Optical
density (0) Is related to the transmittance
and opacity al followl:
0= -log"T
0= -log.. (1-4)
3.12 Peak Optical Response. The wave-
length of maximum senlltlvlty of the Instru-
ment
313 Mean Spectral Response. The wave-
length which blsecta the total area under
the curve obtained pursuant to paragnph
921
3.14 Angle of Vie... The maximum ltotal)
angle of. radiation detection by the photo-
detector assembly of the analy.r. ~
315 Angle of ProJection. The maximum
1 total) angle that contalnl 95 percent of
the radiation projected from the lamp aasem-
bly of the analyzer.
3.18 Pathlength. The depth of emuent In
the llght beam between the receiver and the
transmitter of the single-paso transmla8om-
eter. or the depth of emuent bet..een the
transceiver and reft4!Ctor of a double-pus
transmlMometer. Two pathlengtha are refer-
enced by thll lpeclficatlon:
3 16 I MonltOT Pathlength. The depth of
emuent at the Inatalled location of the con-
tinuous monitoring system.
3 15.2 Emlllton OUtlet Pathlencth. TI\e
depth of elftuent at the location em1uloD8 are
released :0 the atmosphere
4. Installation Specification.
4.1 Location. The tranam15someter must
be located across a sKt10n ot duet or stack
that will provide a partlculate matter flow
through the optleal volume of the tranl-
mlssometer that 18 representative at the par-
ticulate matter flow through the duct OT
stack It 11 recommended that the monitor
path length or depth of emuent for ihe trana-
m'55c~eter include the enUre dl&meter ot
the . ~ Jct or stack. In InstallaUons ustng ..
shor - path length. extra caution must be
URa 1 determlntng the measurement loca-
tlon. ,resentatlve of the particulate matter
now t! ~ough the duct or stack.
4 I I rhe transmlaaometer location .hall
~ down~tream trom &11 particulate control
equipment.
4 1 2 The transmlssometer shall be locat~
"5 tar tram bend8 and obatruct1onl u prac-
tU'31
.. : 3 .0\ transmlssometer that 15 located
In the duct or stack following I bend shall
rye Installed In Ihe plane defined by the
'>el1d where pollible.
RULES AND REGULATIONS
4.1.4 .The transmlssometer ahould be In-
stalled In an accel.lble location.
4.1.5 When required by the Administrator,
the owner or operator of a source must
demonot" te that the tranlmllSometer Is lo-
cated In a section of duct or Itack where
a repreaentltlve particulate matter distribu-
tion exl8ta. The determination shall be ac-
compllahed by examining the opacity proftle
of the emuent at a serlea of posltlona acrOIl
the duct or Itack while the plant 18 In oper-
ation at maximum or reduced operating ratel
or by other telta acceptable to the Admlnla-
trator.
4.2 Slotted Tube. Inltallatlonl that require
the use of a Ilotted tube ahall use allotted
tube of lumclent size and blacknell 10 IU
not to Interfere Wltb the free fiow of emuent
through the entire optical volume of the
tnnamlaaometer or reflect light Into the
tranamla80meter photocletector. Light re-
flectlona may be prevented by ullng black-
ened balllel.wlthin the slotted tube to pre-
vent the lamp radlltlon from Impinging upon
the tube walll, by reltrlctlng the &nile of
projection of the light and the angle of view
of the photodetector aaaembly to Ie.. than
the croaa-aectlonal area of the Ilotted tube.
or by other methods. The owner or operator
must show that the manufacturer of the
monltorlnl IYltem hu uaed appropriate
methoda to minimize light refiectlono for
sYlteml uslnl Ilotted tubes.
4.3 Data Recorder Output. The contlnuoul'
monitoring Iystem output Ihall permit ex-
panded display of the span opacity on a
standard 0 to 100 percent scale. Since all
opacity standards are hued on the opacity
of the emuent exhauated to the atmoaphere,
the system output shall be based upon the
emlllion outlet pathlength and permanently
recorded. For atrected facllItiel whbee moni-
tor pathlengtb II dltrerent from the faclllty'l
emllllon outlet pathlength. a gTaph shall be
provided with the Installation to ahow the
relatlonlhlpl between the continuoul monl-
tortng IYltem recorded opacity baaed upon
the emlllion outlet pathlength and the opac-
Ity of the emuent at"the analyzer location
(monitor path length ). Testl for measure-
ment of opacity that are required by thle
performance lpeclflcatlon are bued upon the
monitor pathlength. The gnph neceaaary to
convert the data reCOTder output to the
monitor pathlength baall Ihall be eatabllahed
as followa:
101 (1-0,> = (1./1,101 (1-4,>
where :
0, = the opacity of the ellluent baaed upon
I,.
O,=the opacity of the emuent bued upon
I,.
I, = the emlaalon outlet pathlength.
.1,= the monitor pathlength.
5. Optical Design Speclficatlono.
The optical d..lgn epeclficatlonl set forth
In section 8.1 shall be met In order for a
meuurement ayetem to comply wltb the
requlrementa of thll method.
e. Determination of Conformance with De-
Ilgn SpeclftcatIOD8.
8.1 The continuous monitortng aystem for
measurement of opacity shall be demon-
Itnted to conform to the dUlgn specltlca-
tlona set forth u follows:
8.1.1 Peak Spectral Reaponse. The peak
spectral relponse of the continuous moni-
toring IYltellUl Ihall occur between 500 nm
and 600 nm. Reaponse at any wavelength be-
low 400 11m OT above 700 nm Ihall be leae
than 10 percent of the peak response of the
contlnUQUI monitor'olly.tem.
6.1.2 Mean Spectral Reeponse The mean
spectral re'po0le ot the continuous monttor.
tnl! .system shan occur between 500 nm and
600 nm.
8.1.3 Angle of View. The total angle of view
shall be no greater than 5 degreea.
8.1.4 Angle of ProJection. The total angle
of proJection Ihall be no greater than 5 de-
gr:~~. Conformance with requirements under
Section 8.1 of thll specification m.y be dem-
onstrated by the owner or operator of the
. .!tected facility or by the manufacturer of
the opacity measurement system. Where con-
formance II demonstrated by the manufac-
turer. certUicat10n that the tests were per..
formed, a description of the teat procedurea,
and the test relul ta Ihall be provided by the
manufacturer. If the source owner or opera..
tor demonltratea conformance, the proce-
dures uled and relulte obtaln8d ahall be re-
ported.
8.3 The general telt procedurel to be fol-
lowed to demoD8trate conformance with sec-
tion 8 requlrementa are given as follows:
(These procedures will not be applicable to
all dellgna and WIll require modification In
some ClUel. Where analyzer and optical de-
sign Is certltled by the manufacturer to con-
form with the angle of view or angle of pro-
Jection lpeclCcatlonl. the rel1'8Ctl ve Pro-
c.dures may be omitted.)
6.3.1 Spectral Response. Obtain spectral
. data for detector, lamp, and filter componenta
uaed In the meaaurement IYltem from their
respective manufacturers.
8.3.2 Angle of View. Set the received up
as apeclfted by the manufacturer. Draw an
arc with radlul of 3 meters. Meaaure the re-
ceiver responle to a small (less than 3
centimeter» n~n-dlre:tlonal light source at
5-centlmeter Intervallon the arc for 26 centl-
metera on either side of the"detector center-
line. Repeat the telt In the vertical direction.
8.3.3 Angle of ProJection. Set the projector
up as Ipeclfied by the manufacturer. Draw
an arc with radlul of 3 metere. Ualng a small
photoelectric light detector (less than 3
centlmeteral. measure the light Intenllty at
ii-centimeter Intervall on the arc for 28
centimeters on either side of the light source
centerline of proJection. Repeat the test In
the vertical direction.
7. Continuoul Monitoring SYltem Per-
formlnce Specifications.
The contlnuoua monitoring aystem shall
meet the performance speclftcatlons In Table
1-1 to be conlldered acceptable under thla
method.
TABLE l-l.-Perfl)rmanrc 8/1crijfcll!iI)'"
Parsmtfn
SfJtdficaNcm.
G. .C.Ubrat1on~"or."--."h_""--
b Zero dr1ft (24 hL... -... ---.. .....
e.CaUbraUon drift (Zt hL...-.....-
d. Response time...................
e. OperationaL test period...........
<3 pet o_lty.'
<2 pet opacity.'
<2 pet opacIIY.'
iOl (maJ.imum).
168 h.
t Ezpressed ILl sum of absolute m..n vatue and thf
9& pet ~onfid.nce intenal of a seriea of tests. .
8. Performance S;>eclficatlon Test Proce-
durel. The following test procedures shall be
used to determine conformance with the re-
qulrementa of paragraph 7:
8.1 Calibration Error and RelpOnse Time
Test. Theae testa are to be performed prior to
Inltallatlon of the IYltem on the stack and
may be performed at the atrected facility or
at other locatloD8 PTOvlded that proper notltl-
cation II given. Set up and calibrate the
meuurement syatem al speclfted by the
manufacturer's. written ID8tructlonl for the
monitor pathJength to be used In the In-
stallation. Span the a.nalyzer as speclCed In
applicable subparts.
8 1.1 Calibration Error Telt. Insert a serlel
of callbrRtlon filters In the tranamlssometer
path at the midpoint. A minimum of three
calibration filters lIow, mid. and hlgh-
rlnge) selected In accordance with the table
under paragraph 2.1 and calibrated WIthin
3 percent mUlt be used. MIke a toUI of five
nonconsecu tI ve readlngl for each CI ter.
FEDElAl IEGISTEI. VOL. 40, NO. 194--MONDAY. OCTOIU 6, 1975
70
-------
Record the meaaurement system output
readings In percent opacity. .See Figure 1-1.)
8.1.2 System Response Test. Insert the
high-range IIlter In the transmlssometer
path five times and record the time required
for the system to respond to 95 percent of
final .iero and high-range IIlter values. I See
Figure 1-2.)
8.2 Field Test for Zero Drift and Calibra-
tion Drift. Install the continuous monttorlng
system on the at/ected facility and perform
the following alignments:
8.2.1 Preliminary Alignments. As soon as
possible aIter Installation and once a year
thereafter when the faclll ty Is not In opera-
tion. perform the following optical and zero
alignments:
8.2.1.1 Optical Alignment. 'AlIgn the light
beam from the tran'3m18someter upon the op...
tical surfaces located across the ellluent (I.e..
the retroflector or photodetector as applica-
ble) in accordance with the manufacturer's
instructions.
8.2.1.2 Zero Alignment. After the transmls-
80meter has been optically aligned and the
transmlssometer mounting Is mechanically
stable 1 I.e.. no movement of the mounting
due to thermal contraction of the stack.
duct, etc.) and a clean stack condition haa
been determined by a steady zero opacity
condition, perform the zero alignment. This
alignment Is performed by balancing the con-
tinuous monitor system response so that any
simulated zero check coincides with an ac-
tual zero check performed' across the moni-
tor path length of the clsan stack.
8.2.1.3 Span. Span the continuous monitor-
Ing system at the opacity specllled In sub-
parts and ot/set the zero setting at least 10
percent of span so that negative drift can be .
quan tilled.
8.2.2. Final Alignments. After the prelimi-
nary alignments have been completed and the
at/ected facility has been started up and
reaches normal operating temperature. re-
check the optical align men t In accordance
with 82.1.1 of this speclllcation. If the align-
ment has shifted. realign the optics. record
any detectable shift In the opacity measured
by the system that can be attributed to the
optical realignment. and notify the Admin-
Istrator. This condition may not be obJec-
tionable If the at/ected facility operates with-
In a fairly constant and adequately narrow
range of operating temperature. that does
not produce slgnillcant shifts In optical
altgnment during normal operation ot the
faclllty. Under circumstances where the facil-
Ity operations produce lIuctuations In the
ellluent gas temperature that result In sig-
nificant misalignments. the Administrator
may require Improved mounting structures or
another location for Installation of the trans-
mlssorneter.
8.2.3 Conditioning Period. After complet-
Ing the post-startup alignments, operate the
system for an initial 168-hour conditioning
period In a normal operational manner.
8.2.4 Operational Test Period. After com-
pleting the conditioning period. operate the
system for an additional 168-hour period re-
taining the zero ofrset. The system shall mon-
Itor the source etftuent at all Urnes except
when betn~ zeroed or calibrated. At 24-hour
Intervals the zero a.nd span shall be checked
~ccordlng to the manufacturer's Instructions.
Minimum procedures used shall provide a
system check of the analyzar Internal mirrors
and all electronic circuitry Including the
tamp and photodetector assembly and shall
Include a procedure for producing a simu-
lated zero opacity condition and a simulated
upscale (span) opacity condition as viewed
by the receiver. The manufacturer's written
Instructions may be used providing. that they
equal or exceed these minimum procedures.
Zero and span the transmlssometer. clean "all
optical surfaces exposed to the ellluent. rea-
RULES AND REGULATIONS
IIgn optics. and malle an y necessary adJ ust-
ments to the. calibration of the system dally.
These zero and cal1brat1on adjustments and
optlcill realignments are allowed only at 24-
hour Intervals or at. such shorter lnt~rvals as
the manu!ac:-turer's written Instructions spec-
Ify. Automatic c~rrecllons made by the
measurement system without operator Inter.
vent10n are allowable at any time. The mag-
nitude of any zero or span drift adjustments
shall be recorded. During this 168-hour op-
erational test period. record the following at
24-hour Intervals: (a) the zero reading and
span readings after the system Is calibrated
(these readings should be set at the same
value at the beginning of each 24-hour pe-
rlod): (b) the zero reading after each 24
hours of operation. but before cleaning and
adjustment; and' (C) t~e span reBdlnv: after
cleaning and zero ad 1ustment. but_before
span ad1ustment. ISee FI~ure 1-3.)
9. Calculation. Data Analysis, Ilnd Report-
Ing.
9.1 Procedure for Determination of Mean
Values and Confidence Intervals.
9.1 1 The mean value of the data set Is cal-
culated according to equation 1-1.
1 n
x=- 2::0,
n ;=1 Equation 1-1
where x, =- absolute value of the individual
meBsuremen ts.
!=sum of the Individual value..
x = mean veJue. and
n = number of data pOints.
9.1.2 The ge percent conOdence Interval
(two-sided) Is calculated according to equa-
tion 1-2:
C.I.,,=~'''-. ,'n(1:-'.')-(1:x,)'
n"n-l
Equalion }-2
where
1:"", ='um of all dnta points.
t ",=t,-",/2. and
C.I...=9.; "prcpnt confidpnc(' intprvnl
....~timflt.... of th.... :1.vf'rng(' m(':ln
valuf.'.
Ynillc, tor 1.971;
-16261
'9';'.')
9.2.3 Angle of ProJection. Us\n~ t~.e da:a
obtained 1n accordance with paragraph 'J J .1
calculate the res,>onse of the photO~lectr;c
detector as a function of proJecUon an~le tn
t\1C horizontal and \'entcal dtrecti;:Jns Ht iL'r:
relal1\'e angle of projecUbn C\1r\'CS a.s r('q:llfl'd
under para~rnph 6.2.
924 Caltbratton Error. Using the datJ. ~r,)m
paragraph 6.1 I Figure I-II. sUbtra": . he
known filter opacity value from tlH' \'a~la~
shown by the measurement system {"T t~at h
of the 15 readings. Calculate the me.\Jl and
95 percent confidence interval of the h\~ dif-
ferent values at e3.ch test ft1ter value :\cc0rd-
tog to equat1~ns 1-1 and 1-2-. Report :.he sum
ot...lbe absolute mean difference and the 95
percent confidence interval for each of the
three test fli ters
9.2.5 Zero Drift. Using the zero opacity
values measured every 24 hours dur111g' the
field test Iparagraph 6.2\, calculate the dif-
ferences between the zero po1nt after clean-
Ing, aligning. and adjustment. and the zero
value 24 hours later just prtor to cleaoln~,
aligning, and adjustment Cillculate the
mean value of these points and the confi-
dence Interval using equations I-I and 1-2
Report the sum of the absolute mean value
and the 95 percent conOdence Interval.
9.2.6 Calibration Drift. Using the span
value measured every 24 hours durtng the
fteld test. calcula.te the differences between
the span value arter cleaning, aligning. and
adjustment of zero and span, and the span
value 24 hours la.ter Just after cl~anln~,
alignIng. and adjustment of zero and borore
adJustment of span. Calculate the mean
value of these points and the cont1dence
Interval using equations I-I and 1-2. Report
the sum of the absolute mean value and the
confidence Lnterval.
9.2.7 Response Time. Using the data from
paragnph 8.1. calculate the time Inter\'al
from IIlter Insertion to 95 percent of the flnnl
stable value for all upscale and downscale
traverses. Report the meM of the 10 upscale
and downscale test times.
92.8 Operational Test Period. During the
16B-hour operational test period, th~ con-
tinuous monitoring sy~tem shall not require
any corrective mn1ntenance, repair. rrpln.ce.
ment, or ad.Justment other than that rlparly
spectfted as required tn the manufacturer'=.
operation Bnd matntenance manuals as rou-
tine and expected durtng a one-week pertod
H the continuous monitoring system LS oper-
ated within the specilled performance pa-
rameters and does not require corrrcth'e
matntenance, repair. replacement. or adJust-
ment other than as spectfied above durtng
the 168-hour test period. the operational
test period shall have been successfullv con.
eluded. Failure at the continuous monitor-
tng system to meet these requtremen ts shall
call for a repetition of the 166-hour teot
period. Portions of the tests which were 5at-
IsfactorUy completed need not be r.peated.
Failure to meet any performance spec1f\ca..
tlon 1 s) shaU call for a repetition of the
one-week oDerational test peTlod and that
specific port1on ot the tests requ1red by
par3graph 8 related to demonstrating com-
pliance with the faUed
-------
~6262
RULES AND REGULATIONS
Calibrated Neutral Density Filter Dati
(See ~aragraph 8.1.1)
low Hid
Range 1 opacity Range ---I opacity
Span Value -----I opacity
fate of Test
location of Test
Calibrated Filterl
Analyzer Reading
1 Opaci ty
2
3
4
5
6
7
8
9
10
11
12
13
14
15
ean difference
Confidence interyal
Icalibration error. Mean
Difference3 . C.I.
low. mid or high rang.
2Calibration filt~r opacity
3"bsolute Yalu~
- analyz~r reading
Figure I-I. Cal:~ratlo~ E~ror Test
Hith
Range ---I opacity
Differences!
S Opacity
low
Hid
High
"'17'''' ~HII hUlllt
.....1.
O"",'f.U-
'"" 't1ter
""~.I.
"'I"" ''''poilU - MUMS
~8C.h.".'T...t-
IQHelt,
'0,.(1(,
11(0"_'
IK'""
...l14li1
lid""
-....
...-.
.......
.......
.......
IIC."
FEDERAL IEGISTEI, VOL 40, NO. 19~NDAY, OCTOIEI 6, 1975
72
'1,...,..1.1.- 1.1",," 'I... '"I
-------
RULES ~D REGULATIONS
Zero Setting (See p.rogro"" 8.Z.1) !)ate of T"'t
Sp.n Setting
Date Zer"O Reac!tng Spa. P.e'" t ocr C.llbrltton
.nd (Berore cl..ntng Zero Drift (Aftr.r clel.l.g .nd .ero Idjusllle.t Drift
TIme Ind .djustaent) (&Zero) but before spa. IdjUStlle.t) (.Span)
Zero Drt ft . Mol. Zero Drift" + CI (Zero) .
Callbratton Drift. Me.. Spa. Drift" + CI (Spill) .
.
Absa1ute YI1u8
Ftgu.. 1-3. Zero 1/111 Cl1tbrltton Drift Tnt
PzarolULUlCZ SPD:IrIc.&no.. 3-PKuoUlAKca
SPJ:Cmc.&nON8 AND aP8CD'ICATiON Tar 1180-
catraU 1'08 IIOIf1T08S CW SO. AIm No.:
FaOK STATJ.OIfA&T SOvac&8
1. Principle and Appltc&blllty.
1.1 Pr1nclple. The concentration of 8uJtur
dioxide or oxlde8 of nitrogen pollutanta In
stack emla8lons 18 meaaured b7 a CODtlnu-
oU81y operating emlll810n meuurement 818-
tam. Concurrent wltb dperatlon of tbe con-
tinuous monitortng sy8tem. tbe pollutant
concentrations are &180 meuured wttb refer-
ence metbode (Appen4lx A). An average of
tbe continuous monitoring 8J8tem data 18
computed for eacb refeJ'Once metbod testing
period and compare4 to determine tbe rel&-
tl ve accuracy of tbe contlnuou8 monitoring
system. Otber testa of tbe continuous mon-
Itoring system are &180 performed to deter-
mine calibration error, drift, and re8pol1lle
cbaracterlstlcs of tbe 8Jlltem.
1.2 Appl.tc&blllty. This performance spec-
LIIcatlon Is appUcable to evaluation of con-
tinuous monitoring systems for meuurement
of nitrogen oxides or sulfur dioxide pollu-
tants. These specifications contatn test pro-
cedures, Installation requirements, and data
computation procedure8 for evaluating tbe.
acceptability of the continuous monitoring
systems.
2. Apparatus.
2.1 Calibration Gu Mixtures. Mixtures of
known concentrations of pollutant gas In a
diluent gas sball be prepared. The pollutant
gas sball be sulfur dioXIde or tbe appropriate
oxlde(s) of nitrogen specLlled by paragraph
6 and within subparts. Por sulfur dioXIde gas
mixtures, the diluent gas may be air or nitro-
gen. For nitric o>
-------
~621H
RULES AND REG"'LATIONS
rr.ltted to demonstrate that the em1..lona
5ampled or viewed are const.tentl, repre..
sentatlve for several typical facUlty proce..
operating condltlona.
4 j Tbe owner or operator may perform a
traverse to characterize any stratllicatlon of
emuent gaaea that might exist In a stack or
duct It no stratification Is present. sampling
procedures under paragraph 4.1 may be ap-
plied even though the ellht diameter criteria
Is not met.
4.4 When lingle point sampling pro~ for
e"trlctlve SYlteD18 are InataUed within the
stack or duct under paragraphe 4.1 and 4.2.1.
the sample may not be e"tracted at any point
Ie.. than 1.0 meter from the ltack or duct
wall. Multipoint sampling probes lnatalled
under paragraph 4.2.2 may be located at any
points necesaary to obtain conalstently rep-
ruentatlVe sampl...
5. ContinuoU8 Monitoring Syatem Perform-
ance Specltlcatlons.
Tbe continuoul monitoring system shall
meet the performance Ipecltlcatlona In Table
2-1 to be conatdered acceptsble under this
method.
TABU: 2-1.-Per;'ONIIGftCe IJIemftcottOM
8p«fJl
-------
equal to the number or samples u data
points.
7.2 Data Analysts and Reporting.
7.2.1 Accuracy (Relative I. Por each or the
nine reference method test points. determ1ne
the average pollutant concentration reported
by the continuous monitoring system. These
average concentrations shan be determined
from the continuous mon!torlng system data
recorded under 7.2.2 by Integrating or aver-
aging the pollutant concentrations over each
or the time Intervals concurrent with each
rererence method testing period. Berore pro-
ceeding to the ne:lt step. determine the -
(wet or dry) or the continuous monitoring
system data and rererence method test data
concentrations. It the baM8 are not con-
sistent, apply a moisture correction to either
reference method concentrations or the con-
tinuous monltorlng syatem' concentratlolUl
as appropriate. Determine the correction
factor by moisture tests concurrent with the
reference method testing periods. Report the
moisture test method and the correction pro-
cedure employed. For each or the nine test
runs determine the durerence ror each test
run by subtracting the -respective rererence
method test concentratlolUl (use average or
ea.::h set or three meuurements ror NO.)
rrom the continuous monitoring system Inte-
grated or 'averaged concentrations. Using
these data. compute the mean durerence and
tbe 95 per~ent confidence IlMerval or the d1C-
rerences (equations 2-1 and 3-21. Accuracy
Is reported u the sum or the absolute Value
or the mean dlllerence and the 95 percent
confidence Interval or the cWl'erences 8:1-
pressed as a percentage or the mean rerer-
ence method value. Use the ezample 8beet
shown In Figure 2-3.
7.2.2 Calibration Error. UBing the data
from paragraph 6.1. subtract the measured
pollutant concentration determined under
paragraph 6.1.1 (Figure 2-1) rrom the value
shown by the continuous mOnitoring syatem
ror each of the five readings at each con-
centration measured under 6.1.2 (FIgure 3-2).
Calculate the mean or these dlll'erence values
and the 96 percent confldew:e Intervals ac-
cording to equations 2-1 and 2-2. Report the
calibration error (the sum or the absolute
val ue or the mean dUl'erence and the 96 per-
cent confidence Interval) as a percentage or
each respective calibration gas concentra-
tion. Use example sheet shown In Figure 3-2.
7.2.3 Zero Drlft (2-hour). Using the zero
concentration values measured each two
hours during the \leld test, calculate tbe d1C-
!erences between consecutive two-hour read-
Ings expressed In ppm. Calculate the mean
dlll'erence and the confidence Interval U8\D1r
IULES AND REGULATIONS
equations' 3-1 and 3-2. Report the zero drlft
as the sum or the ab80lute mean value and
the contIdence Interval as a percentage of
span. Ulle ezample sheet shown In FIgure
2-4.
7.2.4 Zero DrlCt (24-hour). Using the zero
concentration values measured every 24
boure during the field test. calculBte the dlr-
rerences between the zero point aCter zero
adjustment and the zero value 24 hours later
Just prior to zero adjustment. Calculate the
mean Value or th- points and the con11-
dence Interval UsIng equations 2-1 and 2-2.
Report the zero drift (the sum or the abso-
lute mean and con11dence Interval) as a per-
centage or 8p&D. use ezample &beet shown In
FIgure 3-6.
7.2.5 Calibration DrlCt (2-bour). UlI1ng
the calibration values obtatned at two-hour
Intervals during the field test. calculate the
cWl'erences between consecutive two-hour
readlngs ezpressed as ppm. Thea values
should be corrected ror the correspondlng
zero dr1Ct during that two-hour perlod. Cal-
culate the mean and confidence Interval of
these corrected cWl'erence values ustng equa-
tions 3-1 and ~. Do not use the cWl'erenees
between non-conaecutlve read1ngII. Report
the calibration dr1Ct aa the sum or the abso-
lute mean and confidence Interval as a per-
centage or span. Use the ezample sheet shown
In FIgure 2-4. '
7.2.8 Calibration DrICt (M-hour). UBing
the calibration values meaaured every 24
oboure during the \leld test. calculate the d1C-
rerences between the calibration concentra-
tion reading after' zero and calibration ad-
Juatment. and the cal1bratlon concentration
reading 24 bours later aCter zero adjustment
but berore calibration adjustment. Calculate
the mean value or these durerenees and the
con11dence Interval uaIng equations 2-1 and
2-2. Report the calibration dr1Ct (the sum or
tbe absolute mean and con11dence Interval I
aa a percentage or span. Ule the ezample
sheet shown In FIgure 2-5.
7.2.7 Re8ponae TIme. Ua1ng the cbarta
rrom paragraph 6.3, calculate the time inter-
val rrom concentration switching to 95 per-
cent to the IIna1 stable Value ror all upscale
and downka1e teste. Report the mean or the
tbree upscale test times and the mean or the
three downscale _t times. The t..o aver-
..age times should not cWl'er by. more than 15
percent or tbe slower time. Report the slo..er
time as the systeDl response time. Use tbe ex-
ample &beet shown In FIgure 2~.
7.2.8 Operational Test Period. During the
168-hour perrOrm&Dce and operational test
period. the continuous monitoring systsm
8hall not require &by corrective maintenance.
repair. replacement. or adjustment other than
46265
that clearly .peclfled as required In the op-
eration and maintenance manuals &6 routine
and. ezpected during a. one-week perlod. If
the continuous monitoring system operates
within the specified performance parameters
and does not require correcth-e maintenance,
repair, replacement or adjustment other than
as specllled above during the 168-hollr test
period, the operational period wUI be 'I,,'ccss-
full)' concluded. Failure of the l'l1ntln\l('I\lS
monitoring system to meet lhls reqmn'mcill
shall call fot a repetition or tbe 168-hour test
period. Portions or tbe test whIch were satls-
ractorlly completed need not be re pented.
Failure to meet any performance specIfica-
tions shall call ror a repetition of the one-
...,elt performance test period and tha t por-
tion or the testing which Is related to the
railed speclllcation. AU mBlntenance and ad-
Justments required ~all be recorded. Out-
put readings sball be recorded be! ore and
after all adjustments.
6. References.
6.1 "Monitoring Instrumentation for the
Measurement or SulCur Dioxide In StBtlonBrY
Source Emissions," EnvIronmental Protection
Agency, Research TrIangle Park, N.C., Feb-
ruBrY 1973-
8.2 "Instrumentation for the Determina-
tion or Nitrogen Oxides Content of Station-
ary Source Emissions," Environmental Pro-
tection Agency, Researcb Triangle Park. N.C..
Volume I, APTD-0847, October 1971: Vol-
ume 2. ~942, JanuBrY 1972.
8.3 "Ezperlmental Statistics," Department
or Commerce, Handboolt 91, 1963, pp. 3-31,
paragraphs 3-3.l.4.
8.4 "Per!ormance Speclllcations for Sta-
tionary-Source Monitoring Systems for Gases
and Visible EmJS8lons," Environmental Pro-
tection Agency. Research Triangle ParI<. N.C..
EPA-650/2-7~13, January 1974.
....
lI,ff'"",, ",t~OJ
"'l
Mid.lllno. C.llb,.,t1on Gn "t.tUI"I
5_1, I ---1fI8
s..,,1, Z ---1fI8
5...1, J ---JpII
A...,..... ---J'fIA
HIcI~R.lII4I ('D,"I C,11~r.t\OI! '.n "4Ity...
5..1. I --pp-
S88111_DII8
s..1. 3 ---1'"
A...r.,. ---PJI8
FIll"'" 1-1. w1,..ts of ,,11tr,t101l ~u ...t.t\o....~
FEDERAL REGlml. VOL 40, NO. 194-MONDAY, OCTOBEI 6. 1975
75
-------
!6266
RULES AND REGULATIONS
t.1ibrat;on Gas Mixture Data 'From Figure 2-1)
Mid (5~) ----ppI!I
High (901) ----ppil
Ca l1bratlon r.as
Concentratlon.D"'"
Heasurement Syst~
Read I no ODIn
01 fferences 1 DDII
Run'
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Mid
High
Hean till fference
Confident. Interval
-
-
+
+
"ean 01 Herenc.2 + C. 1.
Calibration error. Avera9' Callbrat~on Gas Concentration
x 100~_,
,'Callbratlon gas co~centrat10n . measurement system reading
2Abso1ute valu.
Figure 2-2.
Calibration Error Determination
e '''trlCt ' . "
...1 Dote 5':~' 1 51:" 1 ,..,~,. Z OQ 1111 ~1. .'YZfl" '-MlN, DtHer...c.
... S.~'. J -=1' aw,,..1t (,pIII)- I_I
No.. T,.. I...) I...) 1....1 i_I 50Z NO, 502 NO,
, i I
I
J
. I I
. !
:
6
,
.
,
~~ ,.,f't"PCI ..0018 ,,"n "lr'AftCI _tr.od "',n" 0'
lit ...1.. {SO,} test ftlUI (180.1 tN dt "I""'CI'I
11M'" dt",""c,,- . - (5021.. _(110,).
. KI Cofl"~' 'nten... . . ! PCIIII (SOt). . ~ ,.. (110.).
tl;c" t .""" dtr'rrl'ftCt -',bsolut- ,,'1vel . "I co""d8(1 1nbPw.1 100. I (S~). 1 (110 )
cur.e IS ",.n ,.t er,nr.1 IItthod ¥I "I . - . - . .
[..,11'" .M ",port IIItt"Od ,"" to "'\"",1", l"tflr-ItH ..",......
- ""," dUrerlflcli . thl Iy"r.g' 0' the dt"~"cn 111""1 t'" ...." rtfertftC8 lilt"" tilt ",t.l.
,t"",.,.J. Ace""", Dtt,""'nHlon (SOZ .'WI NO.)
FEDERAL REGISTEI, VOL 40, NO. 194-MONDAY, OCTO.EI 6, 1975
76
-------
RULES AND REGULATIONS
46267
~.. Z..... SPI. Cl1 tb,..Uon
.t TI.. ZI'" Dr'1ft S".. Orlft Drift
;0. 8evtn End Dote Reidt..., ( .ZI...) R..dt"'l (65P1.) ( 5..... ZI...)
1
I
J
.
5
6
7
--
8
9
10
11
II
13
1.
15 -
~I"'. Drtft "J"". Z!", Drift" + CI !!..... ~S~j' 100 " .
CaI1br.tt.. Orlft" [Me.. 5.... Drift" ~ + tl (5..." + [S"..J . 100 " .
."bso1ute Vl1....
'19u", Z-4. Z......ocI Cl1tbr4tt.. Drtft IZ Hour)
Date Zero Span Calibration
and Zero Drift Reading Drift
Time Readi ng (6Zero) (After zero adius tmen t) (6Span)
Zero Dri ft - [Mean Zero Drift. - + C.!. (Zero) ]
t [Instrument Span] x 100 =
Calibration Drift ~ [Mean Span Drift. + C.I. (Span) 1
t [Instrument Span] x 100 = -
. Absolute value
Figure. 2-5. Zero and Calibration Orift (24-hour)
. FEDEIAL UGISTEI. VOL 40, NO. 194-MONDAY, OCTOIEI 6, 1975
77
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16268
[late of Test
RULES AND REGULATIONS
Spu Gu ConcentratIon
Analyzer Span Settl ng
Upsca1.
2
3
Ayerage upscale response
Downscale
2
3
ppr,
Dpal
seconds
seconds
seconds
seconds
seconds
seconds
seconds
Ayerage downscale response _seconds
System Iverage response time (slower tIme) . _seconds.
Idevtatlon from slOt/er . ~verloe uPsclle minus lVerlOe downscalel
system Iverage response [ slower tlone. j
" 1001 - -'
FIgure 2-6.
Response TIme
Performance 8pectftcatlon 3---I'erformance
specUlcatlOD8 and .peclftcatlon te.t pl'OC8-
dures for monitors ot CO. and 0. from sta-
tionary IOUrc88.
I. Principle and Applicability.
\.l Principle. Ellluent gues are continu-
ously sampled and are analyzed tor carbon
dlo"lde or o"ygen by a continuous monitor-
Ing syotem. Te.ts of tbe syatem are performed
durIng a minimum operating period to deter-
mine zero drift, callb..tlon drttt, and 1'8-
5;)onse tlme cbaract.erl8t1cs.
1.~'Appllcabl1lty. Tbll performance specl-
ncatlon Is applicable to evaluation of con-
tinuous monttortnglr.Jtema for measurement
of cubon dlo"lde or o"ygen. Tbue spetlllca-
tlons contain test procedures. Instel.latlon re-
qulremente, and data computation proce-
dures for e"aluatlng tbe acceptabUity of tb8
contlnuoua monitoring syatema KUbJect to
approval by the Administrator. Sampling
may Include eitber eXtractive or nOD-e.trac-
tlve I in-situ) procedures.
2 Appa..tus.
2 I Continuous Monitoring System tor
Carbon Dlo"lde or O"y......
2.~ Calibration 0.. Mlztures. MI"ture or
known concentrations of carbon dioxide or
oxygen In nitrogen or air. MIdrange and 90
percent of apan carbon dioxide or o"Y1!en
concentrations are requIred. The 90 percent
of span gas murture 18 to be used to ..t and
check the analyzer span and Is referred to
as span gas. Por oxygen analyzers, It tbe
span 1a hlgber tban ~l percent 0,. ambient
air may be used In place of the 90 percent of
span calibration gas mixture. Triplicate
analyses or the gaa II11Xture (..capt ambient
air) shall be performed wltbln two weeks
prior to use u8lng Reference Metbod 3 of
tbl. "rt.
2 .81'0 Qu. A pIlCOntalnlng 1888 tban 100
pprr I carbon dioxide or oxygen.
2.4 >&ta Recorder. Analog cbart recorder
or otb 'r suitable de"lce with Input YOltage
range compatible wltb analyzer syatem out-
put. The resolution ot tbe recorde"" data
output shall be 5ull\clent to allow completion
Df the test procedures within this apecUlca-
tloo
J ~nnltlons.
3 1 Continuous Monitoring System. The
t.)tal equipment required for the detennlna.
tlon of carbon dlo"lde or o"ygen In a given
source elllueD't. Tbe .ystem conSiN ot tbree
!D&Jor sUba",tema:
3.1.1 Sampling Interface. That portion at
tbe continuous monitoring system tbat per-
forma one or more or tbe following opera-
tlona: delineation. acqulsltlon. transporta-
tion. and conditioning at a sarnple of tbe
,~urce ellluent or protection ot the an.lyzer
t'rom tbe b...tlle upects or tbe aamp1e or
aourc:e enYtronmeD't.
3.1.~ Analyser. Tbat portlan ot tbe COD-
tlnuou. monltorinl system Rich lenses tbe
pollutant gu and gen_ta a .Ignal output
tbat Is a fUDCtlon of tbe pOollutant concen-
tration.
3.1.3.Data Recorder. Tl!at ponlon of the
continuo... mOnitoring system tIIat provides
a permanent record of tile output 81111101 In
term. of caneenvatlon units.
3.2 Span. Tbe ...Iue ot osYlen or carb:>n dl-
""Ide concentration at whleb tbe contlnuou.
monitoring IJltem II oat that produc.. tbe
IIIaaImum data dlaptay OIItput. Por the pur-
P"'" at tIIl8 metbod, tII. span shall be set
no less tban 1.6 to 2.11 times the normal car-
bon dlo"lde or normal o"Jlen concentration
In the stack g.. of the &frected facility.
3.3 Mld.-nge. The value ot o"ygen or car-
bon dlo"lde concentration tbat -II representa-
tl ve of tbe normal conditions In the stack
1&8 ot the alfected taclllty at typlclll operat-
Ing rates.
3.4 Zero Drift. Tbe ehanp In tbe contin-
uous monitoring IJ'ltem output 0981' a stated
per.locI or time of n'ormal continuous opera-
tion wben tbe carbon dlo"lde or o"fien con-
centrstlon at tbe time tor tbe meuurementl
15 zero.
3.11 Callb..tlon DrIft. Th. change In the
continuous monitoring syatem output o"er a
stated tllII'" period at normal cont1nuoU8 op-
eration when tile carbon dioxide or oxygen
continuous monitoring system 18 meuurtng
tb8 concentration af 8pU1 g&a.
3.8 Operational Teat Period. A IDInlmum
period of time D"er whlcb tbe CODtinuou.
monltortng .yatem 18 e"peeted to operate
wltbln certain performance apecUlcatlons
wltbout unacbeduled maintenance, repair. or
adjustment.
3.7 Response time. The time Intenal tram
a step cbange In concentration at the Input
to tbe contlnuoU8 monitoring syatem to tbe
time at which gll percent of tile correspond-
Inll tlnal value 11 dlIplayed on tbe cantlnUDUS
monitoring system data recorder.
4. Inatallatlon Specification.
OxJlen or carbon dlo"lde continuous mon-
ltorinl syate1D8 sball be Installed at a loca-
tlan where meuurementa arlt directly repre-
..ntatlve of tbe total ellluent from the
&frected facl\lty Dr representative of the .ame
ellluent sampled by a 50, or NO. contlnuDUS
monitoring syatem. This requirement shall
be compiled wltll by u.. af applicable re-
quirements In Performance Speclftcatlan 2 at
thll appendix u tollo...:
4.1 Inatallatlon Of Oxypn or Carbon Dl-
ol:l4e ContinuoU8 Monltor1D8 Sy_1D8 Not
Uzed to Canvert Pollutant Data. A'sampllng
location shall be ..Iected In &coordan.. wltll
tile procedures under pararraphs 4.2.1 or
4.2.2, or Performance Specification 2 at tb1a
appendix.
4.2 Installation af Oxygen ar Carbon DI-
ol:l4e Continuous Manltorinl Systems Used
to Conven Pollutant ContlnuoU8 Monitoring
System Data to Units at Applicable Stand-
ards. The diluent continuous monitoring sya-
tem (oxygen or carbon dlo"lde) sh.1I be In-
stalled at a ..mpllng locatlan where meuure-
ments that can be made Ire representative at
the ellluent gues sampled by the pollutlLDt
contlnuou. monitoring syatem(s). Confarm-
ance with thll requirement may be accom-
plished In any ot the tollawlng waya:
4.2.1 Tbe sampling location for :he diluent
system shall be near tbe sampling location for
tbe pollutant contlnuaus monitoring lyatem
such that the same appro"lmate po1Dt(.)
(extractive syatama) or path (In-situ s"'-
tems) In tbe trOU section 18 sampled or
viewed.
4.2.~ Tbe diluent and poUutant continuous
monltortng systems may be Installed at cI1t-
f.orent locatlona It the ellluent 188es at both
umpllng 10cat10D8 are nonstratltled 88 deter-
mined under paragrapha 4.1 or 4.3. Perform-
ance SpecUlcatlon ~ af tbl. appendIX and
tbere Is no In-leakage occurring between tbe
two sampling locations. It the ellluent g-
are atratlfted at eltber location, the proce-
dures under paragrapb 4.2.2, Pertormance
Specltlcatlon ~ ot tbll appendIX shall be used
tor lnatalllng continuous monitoring syatema
at that location.
S. ContlnuoU8 MODltortnr Syatem Perfarm-
ance Specltlcatlona,
The continuous monitoring system shall
meet tbe performance specltlcatlons In Table
3-1 to be considered acceptable under tbl8
method.
8. Performance Specltlcation Test Proce-
dures.
The following test procedures shall be used
to deterlDlne conformance wltb the requlre-
m.onts of paragraph 4. Due to the wide varia-
tion eal8tlng In analyzer designs and princi-
ples ot operation, tbe.. procedures are not
applicable to all analyzers. Where tbls occurs.
alternative procedures, ,ubJect to the ap-
pro"aI ot tbe Administrator. may be em-
ployed. Any sucb alternative procedurea mU8t
fuUIII tbe .ame purpo... ("erlty response.
drift. and accuracy) 88 tbe tallaWing proce-
dures. and must clearly demonstrate con-
formsnce wltb Ipaclflcatlons In Table 3-1.
8.1 Calibration Check. Establish a cali-
bration curve for the continuous mom-
taring system using zero, midrange, and
span concentration gas mixtures. Verify
that the resultant curve of analyzer read-
Ing compared with the calibration gas
value Is consistent with the expected re-
spOnse curve as described by the analyzer
manufacturer. If the expected respOnse
curve Is not produced. additional cali-
bration gas measurements shall be made.
or additional stepS undertaken to verify
FEDERAL IRISTO, VOL 40, NO. 194-MONDAY, OCTOIEI 6, 1975
78
-------
the accuracy of the response curve.of the
analyzer.
6.2 Field Test for Zero Drift and Cali-
bration Drift. Install and operate the
continuous monitoring system In accord-
ance with the manufacturer's written In-
structions and drawings as ~llows:
TABLE 3-l.-Pertormance specijlcatiOfts
Pa"",,""
Sr>oolul8 mean valua plus 95 pet
conlldance Interval oro series 0118010.
6.2.1 Conditioning Perioc1. Offset tbe zero
setting at least 10 percent of span 80 that
negative zero drift may be quantl1led. Oper-
ate the continuous monitoring system for
an Inlttal 168-bour conditioning perlDg In a
normal operational manner.
6.2.2. Operational Test Perioc1. Operate the
continuous monitoring system for an addi-
tional 168-bour period maintaining the zero
offset. The system shall monitor tbe 80urce
emuent at all tlmea e"cept wben being
zeroed. calibrated. or backpurged.
6.2.3 FIeld Test for Zero DrUt and Calibra-
tion Drift. Determine tbe valuea given by
zero and midrange gas concentrations at two-
bour Intervals until 15 sets of data are ob-
tained. Por non-utractlve continuous moni-
toring oystems, determtne the zero value
given by a mecbantc&Uy produced zero con-
dition or by computing the zero value from
upscaJe measurements using calibrated gas
cells certl1led by tbe manufacturer. The mid-
range cbecu sball be performed by using
certl1led calibration gas cella functionally
equ1valent to 1- tban 50 percent of span.
Record tbese readings on the eKample sheet
sbown In Figure 3-1. These two-bour perloda
need not be consecutive but may not overlap.
In-situ CO, or 0, analyzers wblcb cannot be
IItted wHb a calibration gas cell may be cali-
brated by alternative procedures acoeptable
to tbe Admlnlatrator. Zero and calibration
corrections and adjustments are allowed
only at 24-bour Intervals or at sucb shorter
Intervals as tbe manufacturer's written in-
structions specify. Automatic corrections
made by tbe continuous monitoring system
wltbout operator intervention or Initiation
are allowable at any time. During tbe en-
tire 166-bour test period. record tbe values
given by zero and span gas concentrations
berore and after adjustment at 24-bour In-
tervals In tbe e"ample sbeet shown In FIgure
3-2.
6.3 Field Test ror Response TIme.
6.3.1 Scope of Test.
This. test sball be accompllsbed using the
continuous monitoring system as Installed.
Including sample transport lines If used.
Plow rates. line diameters. pumping rates,
pressures (do not allow tbe pressurized call-
bratlon gas to cbange tbe normal operating
pressure In the sample line). O'tc., shall be
at tbe nominal values for normal operation
as specl1led In the manufacturer's written
Instructions. If tbe analyzer Is used to sample
more tban one source (stack J. tbls test sball
be repeated for eacb sampling point.
6.3.2 Response Time Test Procedure.
Introduce zero gas Into tbe continuous
monitoring system sampling Interface or as
close to the sampling Interface as possible.
When tbe system output reading bas &tabl-
RULES AND REGULATIONS
l!zed, swltcb qulclt1y to a known concentra-
tion of gas at 90 percent of span. Record the
time from concentration swltcblng to 95
percent of IInal stable response. After tbe
system rellJ)OD89 bas stabilized at tbe upper
level, swltcb quickly to a zero gas. Record
tbe time from concentration switching to 95
percent of IInal stable respon"". Alterna-
tively, for none"tract1ve continuous monitor-
Ing sy.tems, tbe blgberrlly
completed need not be repeated. Failure to
meet any performance specilications shall
call for a repetition or the one-week pertorm.
ance test period and tbat portion or the test.
Ing wblcb 18 related to the tailed speclt1ca'
tlon. All maintenance and adjustments re-
quired sball be recorded. Output readings
shall be recorded berore and atter all ~d.
Justments.
7.2.6 Response Time. Using tbe data devel-
oped under paragrapb 5.3. calculate the time
IntervaJ rrom conceIjtratlon switching to 95
percent to tbe IInal stable value ror all up-
scale and downscale tests. Report the mean or
the tbree upscale test times and tbe mean or
the three downscale test times. The two av-
erage times sbould not dJlrer by more :ban
15 percent of the slower time. Report tbe
slower time as the system response time. Re-
cord tbe resu1 18 on Figure 3-3.
8. References.
8.1 "Performance Specilications ror Sta-
tionary Source Monitoring Systems tor GB.ses
ond Visible Emissions," Envlronmen:al Pro-
tection Agency, Researcb TrIangle Park, :;.C..
EPA-650/2-74-013, January 1974.
8.2 "Experimental Statistics," Department
or Commerce, National Bureau of Standards
Handbook 91, 1963, pp 3-31. paragraphs
3-3.1.4.
(Secs. 111 and 114 of tbe Clean Air Act. as
amended by sec 4(a) ot Pub L. 91-604, 84
Stat. 1678 (42 US C. 1857c-6, by sec 15, c) ,2)
of Pub. L. 91-604. 85 Stat. 1713 (42 C; S C.
1857g» .
FEDERAL REGISTER, VOL 40, NO. 194-MONDAY, OCT08ER 6, 1975
The valuea In tbis table are already corrected
for n-1 degrees or treedom. Use n eq ual to
tbe number of samples as data points.
7.2 Data Analysis and Reporting.
7.2.1 Zero Drlrt (2-hour). Using tbe zero
concentration values measured each two
bours during tbe lIeld test. calculate the dif-
ferences between the consecutive two-hour
readings e"pressed In ppm. Calculate the
mean difference and the confidence interval
using equations 3-1 and 3-2. Record the sum
of tbe absolute mean value and tbe con1l.
dence interval on the data sheet shown 1n
Figure 3-1.
7.2.2 Zero Drift (24-hour). Using tbe zero
concentratic7n values measured every 24
bours during tbe lIeld test, cal"ulate the dif-
ferences between the zero point after zero
adjustment and tbe zero value 24 bours
later Just prior to zero adjustment. Calculate
tbe mean val ue of tbese points and tbe con-
IIdence Interval using equations 3-1 and 3-2.
79
-------
-16270
RULES AND REGULAnONS
~~
o.
TI-
loti. [04
Oato
ZoPo
_I..
Zoro
Orlft
(,Z,,,,)
s,u.
lit"'""
s,u.
DrIft
(dpu)
CAlIb",U..
Drift
(.s,o..oZo",)
fl-
,
,
ho
z.
fro t.~:CUtf"O C. ....
t,1tbr.t1on O,tft . [f4t,n SIN" ~ . CI (
.~..ll1te YalW1. -
'I,.... )-1. Zoro ,.d CAltbrtU.. DrIft (Z -I.
pate Zero Span Ca1tbration
nd Zero Drift Reading Drift
i.. Reading (toZero) (After zero adjustment) (65pall)
ero Drift. [Hein Zero Drift. + C.t. (Zero) ]
. .
:.1tbration Drift. [Mean Span "'Drift. + C.t. (Span) ]
. .
Abs01ute va1ue
Figure 3-2. Zero and C.1ibrat1on Drift (24-hour)
FEDERAL IEGISTEI, VOL 40, NO. 194-MONDAY, OCTOIEI 6, 1975
80
-------
RULES AND REGULATIONS
M271
Dati: of Test
Span Gas Concentration ppm
Analyzer Span Setting ppm
1. seconds
Upscale 2. seconds
3. seconds
Average upscale response
seconds
1. seconds
Downsca 1 ~ 2. seconds
3. seconds
Average downscale response
seconds
ystem ~verage response time (slower time) .
seconds
.. J..'i04t "" from 5 1 o'~er -
ystem average response
averaoe uDscale mieus averaoe downscale
slower tIme
x lO~
Figure 3-3.
Response
IPR Doc.7~2811e1i PIlec11G-3-71i;8:41i ami
FEDERAL REGISTER, VOL 40, NO. 194-MONDAY. OCTOBER 6, 1975
81
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~
VI
--
(i)
!
e
.
-0
J!
TUESDAY, OCTOBER 12, 1976
PART III:
ENVIRONMENTAL
PROTECTION
AGENCY
Emission Monitoring
Requirements
.
RECEIPT OF APPLICATION
AND APPROVAL OF
ALTERNATIVE
MONITORING
REQUIREMENTS
83
-------
1-t8;38
NOTICES
ENVIRONMENTAL PROTECTION and oxides of nitrogen eml88Jons from
AGENCY fosail fuel-fired steam generatons when
. the pollutant and o~en concentrations
(JI'RL 826-3) are meuurec1 on a wet bula exoept where
EMISSION MONITORING REQUIREMENTS wet IUUbbens are employed. or where
--'I tI nd ,,- I of molsure Is otherwise added to the stack
Receipt of A",~ C8 0" 8....~ gaaea'
Alternative Monitorlnc Requirements .
On October 8,1975 (40 FR 48247 and B-C..F. (209 (1-:.9)-% )
48258), and on August 20, 1978 (41 FR ... 0,..
35185) the Environmental Protection where:
Agency (EPA) promulgated regulations 1. E=pollutant emission, g/mIllion cal
under 40 CFR Parts 51 and 80 which re- (lb/mIlllon Btu).
quire continuous em1ssion monitoring of 2. C...=pollutant concentration at
sulfur dioxide and oxides of nitrogen at stack conditions, g/wscm (1r&1D8/wet
new and certain existing fOls.ll fuel-ftred standard cubic meter) Hb/WICt
steam generators. The regulations require (pounds/wet standard cubic foot», de-
that the emission rate be computed using termined by multipl:!'lng the average
an equation which reQuires the measure- concentration (ppm) for each one-hour
ment of the pollutant concentration and period by 4.15X 10'" II g/wscm per ppm
percent oxygen In the stack gas on a dry C2.59X 10'" II Ib/wlCt per ppm) where
basis only. However, paragraph 3.9.1 of II-pollutant molecular weight, g/r-
ApJ>I'ndlx P to 40 CFR Part 51 and mole (lb/lb-mole). M=84.07 for sulfur
~ 60.13(1) (3) of 40 CFR Part 80 provide dioxide and 48.01 for nitrocen oz1des.
for application for approval of "altern- 3. 'JI,O,....=oxygen volume (expressed
atlve monitor1na requirements to accom- aa percent.-wet-baals determined with
modate continuous monJtor1na systems equipment speclfted under paragraph
that require additional measurements to (d) of section 80.45.
correct for stack moisture conditions." 4. P.=a factor representing a ratio
EPA has received two written appllca- of the volume of wet due IJ8HIlmerated
tions for approval of alternative monltor- to the calorlftc value 'of the fuel com-
Ing requirements; one waa received from busted. Values of F.. are riven aa folloW8:
Lear Siegler, Incorporated, Englewood, <1) For anthracite coal as .c1uslfted
Colorado, on January 9, 1978, and one according to A.S.T.M. D388-68, F..=1.188
from E. I. duPont de Nemours and Com- W8cm/mWion cal <10580 WBCf/miWon
pany, wUmIn~, Delaware, on Janu- Btu).
ary 23, 1978. Specifically, the applicants (11) For sub-bituminous and bituml-
requested approval of alternative emls- nous coal aa classlfted accordinr to
slon data reduction procedures to be used A.S.T.M. D388-68, F..=1.2oo wscm/
with wet-basis stack gaa pollutant and million cal <10880 wsef/millIon Btu>'
oxygen monitorinr data from fossil fuel- (111) Pol' liquid fossil fuels including
tired steam generatons. EPA has com- crude. residual, and distillate oils, F..=
pleted a technical review ot the appltca- 1.184 WllCm/mWlon cal (10360 W8et/mil-
tlons and approves the following alterna- lion Btu) .
tlve data reduction procedures uslnr wet- flv) For gaseous fossil fuels: For
basis pollutant and oxygen data tor new natural gaa, F..=1.196 wscm/miWon cal
stationary sources regulated by 40 CFR <10850 wset/milllon 8tu). For propane,
Part 80. State control agencies may in- F..=1.150 wscm/m1l1lon cal <10240 wacf/
I d th d ta d tl techni in m1l1lon Btu), For butane. F..=1.172
cue ese a re uc on que. W8Cm/mWlon cal (10430 wset/mIllion
their Implementation Plans. Btu).
... The followtnr equation may be used Values of F.. may be determined from
for the determination of sulfur dioxide a fuel ir.nalysls aa folloW8:
F =347.4 %H+9,~.7 %C+3H %8+8.6 %N-28.5 %0+13.4 %H,O'
. GCY.
(Metric)
F _1()o[5..~fi %H+1.53 %C+0.57 %8+0.14 %N-0.46 %0+0.21 %B,o.)
.- GCY.
(English)
I ThJ. tf'nn mAy ~ ondlte-J It ':"~ II +~ 0 mclud.'s the unavailable hydrOlt"D and ozygen in the form 01 D.O.
where:
H, r S. N, and 0 ""' content by weight
of hy 'ogen. carbon, oulfur, D1trogen, and
oxygo (e"Pre_.. percent). rt!llpectlnly.
8A de'. mined on the .ame balsa ILl aev.
by ult\>. ate analysla of the tuel lIred, uolng
... S.T.lII. methOd D3178-74 or D3178 loolld
fuels), or computed from result8 using
hS.T.~I. methOds D1l37....!13(70), D194~4
(73), or D1948-87('72} (gaseous fuels, ..
Rppll B..=0.027. ThIa factor may be used
aa a constant value at any location.
(II) B..=highest monthly average ot
B-. which occurred within a calendar
year at the nearest Weather Bureau
station.
(UI> B-.=highest dany average of
B.. which occurred within a calendar
month at the nearest Weather Bureau
station, calculated trom data for the past
three years. Thla factor shall be calcu-
lated tor each month and may be used as
an estimating factor for the respective
calendar month.
b. The following equation may be used
tor the determination of sulfur dioxide
and oxides of nitrogen pollutant emis-
sions trom f068i1 fue1-flred steam gen-
erators where the pollutant and oxygen
concentrations are measured on a wet
baals. and the water vapor content of the
stack ..... Is determined at least once
every fifteen minutes. When wet scrub-
bers are employed prior to where the
stack gaa Is sampled or If liquid water
droplets or mist Is otherwise present In
the stack gas, use of a heated extractive
monitoring system may collect and vap-
orize condensed liquid. As a result, the
vapor content of the .tack aas may be
sign1f1cantly different from the vapor
content where the pollutant and oxygen
concentrations are measured. Therefore,
in aU applications of the tollowlng equa-
tion, the water vapor content must be
measured In the monitoring system or
stack such that the meaaured vapor con-
tent Is the same aa the vapor content
existing at the point where the pollu-
tant and oxygen measurements a.l'e
made.
E=C..F (20.9(1-;~'~-%O,J
where:
1. E=pollutant emission, a/million cal
-------
5. Bw.=proportlon by volume of water
vapor In the stack gas.
This equation 18 approved In principle.
Approval for actual practice 18 contln-
g&nt upon demonstrat1n8 the ability to
accurately determine B., such that any
absolute error In B., will not cause an
error of more than :!:1.5 percent In the
tenn
( 20.9 )
20.9(1-8.,)-%02..
lIIPACT or ACTIOK OK STAn:
IKPLIUIDTATIOll PLANs
In accordance with regulations pro-
mulgated by the ABency on October 8,
1975, states are required to submit regu-
NOTICES
lations that provide for continuous emis-
sion monitoring of certain existing
sources. Such State regulations shall be
submitted to EPA for approval and shall
be considered a revision to the approved
state Implementation Plan. According
to the EPA requirements. States shall
set forth performance specifications for
monltorlna Instruments and require that
data derived from such monitoring be
summarized and made available. Mini-
mum performance standards and other
procedures are set forth In 40 CFR Part
51, Appendix P. These requirements allow
States to consider alternate procedures
when such procedures are determined to
be l1li accurate as those contained within
Appendix P.
.wS39
States are advised that as a result of
this notice. EPA now approves the use
of two alternate data reduction proce-
dures not currently contained within Ap-
pendix P. It should be noted that this
action does not mandate acceptance or
use of these alternate procedures by any
State. This action does. however. signify
the Agency's Intent to approve state
plans employing these data reduction
procedures where States determine that
such procedures are amendable to their
control programs.
Dated: September 30.1976.
RoGER STRELOW.
Assistant Administrator
lor Air and Waste Management.
[PR Doc.78-29710 PIled 10-8-78;8:45 a.ml
IIDHAL REGISTER, VOL 41, NO. 198-TUESDAY. OCT08ER 12, 1976
85
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J9
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--
CD
!
e
.
-0
..!
MONDAY, JANUARY 31, 1977
PART X
,,'I\,'I£S OF,..
I""''f'~~ ~ ~<"c:.'
I~ ~
12 ~
\~ " 0
\~ . . .l~
V-s-.{ 'C- ~'y
. 1934 .
ENVIRONMENT AL
PROTECTION
AGENCY
.
REVISIONS TO EMISSION
MONITORING
REQUIREMENTS AND TO
REFERENCE METHODS
87
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5936
Title 4O--Protection of Environment
CHAPTER I-ENVIRONMENTAL
PROTECTION AGENCY
I FRL 669-4 I
PART 6o-STANOARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Revisions to Emission Monitoring
Requirements and to Reference Methods
On October 6. 1975 (40 FR 46250).
under sections Ill. 114, and 301 of the
Clean Air Act, as amended. the Envi-
ronmental Protection Agency (EPA)
promulgated emission monitoring re-
quirements and revisions to the perfonn-
ance testing Reference Methods In 40
CFR Part 60. Since that time. EPA has
determined that there I.S a need for a
number of revISions to clarify the re-
qUirements. Each of the revisions being
made In 40 CFR Part 60 are discussed
as follows:
I. Section 60.13 Paragraph (c) (3) has
been rewritten to clarify that not only
new monitoring systems but also up-
graded monitoring systems must comply
with applicable performance specifica-
tions.
Paragraph (e) (1) is revised to provide
that data recording is not required more
frequently than once every six minutes
, rather than the previously required ten
seconds) for continuous monitoring sys-
tems measuring the opacity of emISsions.
Since reportst of excess emissions are
based upon review of six-minute aver-
ages. more frequent data recording Is
not required in order to satisfy these
monl tOrlng requirements.
~. Section 60.45. Paragraphs (al
through' e I have been reorganized for
clarificatIOn. In addition. restrictions on
use of continuous monitoring systems for
measunng oxygen on a wet basIS have
been removed. Prior to this renslon. only
dry basis oxygen mOnitoring equipment
was ac~eptable. Procedures for use of wet
basIs oxygen mOnitoring equipment have
been approved by EPA and were pub-
lished In the FEDERAL RECISTER as an al-
ternative procedure (41 FR 44838).
Also deleted from! 6045 are restric-
tions on the location of a carbon dioxide
'CO' continuous monitoring system
downstream 0: wet scrubber flue gas de-
sulfurlzatlon equipment. At the time the
regul:!.tlOns were promulgated (Octo-
be. 6. 1975\, EPA thoul{ht that limestone
scrubbers were operated under condi-
tions rhat could cause significant gen-
eratIOn or absorption of CO. by the
scrubbing solution which would cause
~rror< n the monitorml{ results. EPA in-
n,t!,' ,ed thIS potential problem and
cone' :ed that lime or limestone scrub-
bers der typical conditions of opera-
tion c. not significantly alter the con-
centr81 on of CO In the flue gas and
would c.ot introduce <1I1n1f1cant errors
into t !~e rr.nmtorlnl{ re,ults Lime scrub-
be" uJerate at a pH ~e"el hetween 7 and
8 \\ hlch will maximIZe SO. absorption
and mlr.lmlze CO absorption Thus. the
effect of CO loss on the emISSion result,
IS expected to he minimal The exact
amollnt of CO !0'S. if any. durmg the
sc cubber opera, "on has not been deter-
RULES AND REGULATIONS
mined since it is dependent upon the
operating conditions for a particular fa-
cility. Although each percent of CO, ab-
sorption will result In a positive bias of
7.1 percent (at a stack concentration of
14 percent CO, I In the final emission
results. i.e. the indicated results may be
higher than actual stack concentrations,
the actual bias is expected to be very
small since the amount of CO, absorp-
tion wl\l be much less than one percent.
In flue gases from limestone scrubbers.
there exists a possibility of the addition
of CO. from the scrubbing reaction to
the CO, from the fuel combustion. Every
two molecules of SO, reacting with the
limestone will produce a molecule of Co..
Limestone scrubbers are typically oper-
ated at an approximate temperature of
50' C under acidic conditions. At these
operating conditions the amount of CO.
generated In a 90 percent emclency
scrubber is 1350 ppm or 0.135 percent
CO,. This will Introduce a negative bias
of I to 1.5 percent for a CO, level of 8 to
15 percent. This amount of potential
error compares favorably with systems
prevIOusly approved. Therefore. EPA is
removing the restrictions which limited
the Installation of carbon dioxide con-
tinuous monitoring svstems to a location
upstream of the scrubber.
Several other revisions are being made
to paragraphs (a), (b). IC). and 'el of
Suboart D which imorove the clarity or
further define the intent of the regula-
tio"s. Para~raph «1\ ha, been rp,erved
for later addition of fuel monitoring pro-
visions.
3. Performance S"ecification 1. Para-
grach 8.2 has been rewritten to clarify
requirements that must be met by con-
tinuous opacity monitor manufacturers.
Manufacturers must certify that at least
one analyzer from each month's produc-
tion was te'ted and meets all apclicable
requirements. If any reqUirements are
not met. the production for the month
must he rp
-------
(2) For a fosslJ fuel-fired steam gen-
erator that does DOt use a fiue gas de-
sulfurlzation device, a continuous monl-
tormg 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.
(3) Notwithstanding I 60.13(b), In-
stallation of a continuous monitoring
system for nitrogen oxides may be de-
layed until after the initial performance
tests under I 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
I 60.44, a 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 160.8 and comply
with all other applicable monitoring re-
quirements under this part.
(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 Ib' (3) of this section a continuous
monitoring system for measuring either
oxygen or carbon dioxide is not required.
IC' For performance evaluations un-
der $ 60.13(c) and calibration checks
under 160.13(d>, the following proce-
dures shall be used:
(1' Reference Methods 6 or 7, as ap-
plicable. shall be used for conducting
performance evaluations of sulfur diox-
Ide and nitrogen oxides continuous mon-
itoring systems.
(2' Sulfur dioxide or nitric oxide. as
applicable. shall be used for preparing
calibration gas mixtures under Perform-
ance Specification 2 of Appendix B to
this part.
13' For altected facilities burning fos-
sil fuel IS '. the span value for a continu-
ous monitoring system measuring the
opacity of eml5slons shal1 be 80, 90. or
100 percent and for a continuous moni-
toring syStem measuring sulfur oxides or
nitrogen oxides the span value shal1 be
determmed as follows:
(Tn partS f\l'r million]
r J:..!.I [UP\
$pon \"alUf lor
sulfur dioxide
Span t"31ue (or
nitrolen oXIdes
t .as...-..
LI'1...:r1...
~n~~~ . 1110n5::
(I)
500
500
sm
500(1"'.>+1.000,
1.000
1.500
1.tIOOU1'" 1.500:
- -------~-
-----
;<\ .1jlphcable.
where
. c : C.O fraction of total heat Inpu t
fro:,:: ga.!.teous f05sl1 fuel. and
'c.. :ractton of total heat Input
::C~1 liquid fossil fuel. and
z" ::~e fraction of total heat 1np1.lt
::0:1'. solid fossil fuel.
derl"ed
dert ,'ed
derl ,'od
(4) AI1 span values computed under
paragraph t C' (3) of this section for
burnmg combinations of fossil fuels shall
be rounded to the nearest 500 ppm.
(5' For a fossil fuel-fired steam gen-
erator that simultaneously burns fossil
fuel and nonfossil fuel the span value
of al1 continuous monitoring systems
shall be subject to the Administrator's
approval.
(d) [ Reserved]
(e) For any continuous monitoring
system Installed under paragraph (a) of
this section. the following conversion
procedures shall be used to convert the
continuous monitoring data into units of
the applicable standards fng/J. Ib/mil-
lion Btu) :
(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 fOllowmg conversion procedure
shal1 be used:
E=CF [ 20.9 ]
20.9-percent 0,
where :
E. C. F. and ':'00. are determined under pa.ra-
graph (f) of tlit.s section,
(2) When a continuous monitoring
system for measuring carbon dioxide Is
selected. the measurement of the pol-
lutant concentration and carbon dioxide
concentration shall each be on e. con-
sistent basis (wet or dry) and the 101-
lowing conversion procedure sha.U be
used:
E-CF [ 100 ]
- 'percent CO,
where :
E. C. F. and '
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26205
Title ~rot8Ctlon of Environment
CHAPTER !-ENVIRONMENTAL
PROTECTION AGENCY
[PRL '711-8]
PART 6O-STANDARDS OF PERFORM.
ANCE FOR NEW STATIONARY SOURCES
Compliance With Standards and
Maintenance Requirements
AGENCY: Environmental Protection
Alencr.
ACTION: FInal rule.
SUMMARY: ThI8 action amends the
lenera.l provtalOl18 of tbe standarda of
performance to aDow methods other
than Reference Method II to be used as a
means of meaa~ plume opact~. The
Environmental Protection "-mcr IEPA)
18 Inveattaattnc a remote sen.aln. laaer
radar Intem of meuurln. plume opacity
and blUe... It could be cODIldered as an
altematln method to Reference Method
II. ThJs amendment would aDow EPA to
propose such .ysterna as alternative
methods In the future.
EFFECTIVE DATE: June 22, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, EmissIon Standards
&.nd Eng1neerlng DIvisIon, En.1ron-
mental Protection Agency, Raean:h
Tr1angle Park, North CarolJna 27711,
telephone no. 91~8B-8all, ext. 271.
SUPPLEMENTARY INPORMATION:
Aa ortgtn.a1ly expressed, 40 CFR 110.11 Ib)
permitted the use of Reference Method 9
DelusIvely for detennIDlng whether a
80urce compiled with an appilcab1e
opacIty standard. By this action, EPA
amends I 60.11 (b) so that alternative
RULES AND REGULATIONS
methoda approved br the Adrn1nlstrator
may be used to determine opacity.
When 180.11lb) was ortalnally pro-
mul8ated, the vtslble emissions IMethod
.) technJque of determining plume
opacIty with trained visIble emission ob-
.erven was the only expedient and accu-
rate method ava11able to enforcement
personnel. Recently, EPA funded the de-
ftlopment of a remote sensing laser ra-
dar mtem ILIDAR) that appears to pro.
duce reaultl adequate for determination
of compl1ance with opacIty standards.
EPA 18 currently evaluating the equip-
ment and 18 considering proP05lng Its
aae as an alternatIve technique of meas-
uring plume opacity.
This amendment wUl allow EPA to
consIder use of the LIDAR method of
determining plume opacIty and, If ap-
propriate, to approve this method for en-
forcement of opacity regulations. If this
method appean to be a suItable alterna-
tin to Method 9, It wW be proposed In
the FEUEIIAL REGISTER for public com-
ment. After consIdering comments, EPA
'If1ll determine If the new method will be
an acceptable means of determining
opacIty compliance.
18eca. 111. 114. 301 (a), Clean Ai. Act. see 4(a)
01 Pub. L. 1I1~, 1M Stat. 1M3; aec. 4(a) ot
Pub 1.. 1I1~ 1M Stat. 1887: 811C. 2 ot Pub. 1..
Ro. 110-1". 81 Sta&. 604 142 U.s.C. 1857cH1.
1867c-1I and 1857.la).)
Nan..-Economlc Impact Analyala: The
8nY1n>nmentai Pro&ec&1on "ceDeJ baa deter-
_ad &bat &b18 action doea DOt contaID a
-Jor propoaal req u1rt.ng prepara&1on ot an
8Donomic Impact AnalJ8Ia under Buc:utl..
QI'den 11821 and 11l14li and OMB C1.""lar
A-I07.
Dated: May 10, 1977.
DoUGL\S M. C'OSTLE,
Admi7liltrator ,
26206
Part 80 of Chapter I, TItle 40 of the
Code of ~era.l RegulatIons Is amended
.. toDows:
L SecUaD 80.11 18 amended by revtslnc
~ (11) .. foUowl:
160.11 C-pliaDee ..lIh stand.rd. and
mama_DCe requiremenIL
.
.
.
(I) OCImpl1anoe with opacity ltand-
III'd8 In tbI8 pan sb&Il be determined b1
conducting observations In accordance
with Reference Method 9 In Appendix A
of th1s part or any alternative method
that Is approved by the Adrn1nJstrator.
OpacIty readings of portions of plwnes
whIch contain condensed, uncombined
water vapor shall not be used for pur-
p05es of determining compliance with
opacIty standards. The results of con-
tinuous monItoring by transmlssometer
whIch indicate that the opacity at the
time visual observations were made was
not In excess of the standard are proba-
tive but not conclusive evidence of the
actual opacity of an emissIon, provided
that the source shaU meet the burden of
proflng that the Instrument used meets
lat the time of the alleged violation)
Performance Specification 1 In Appendix
B of this part. has been properly main-
tained and lat the time of the alleged
violation> calibrated, and that the
resulting data have not been tampered
with 111 any way.
(BeC!!. 111, 114, 301 (a), Clean AIr Act, Sec. 4
(a) ot Pub. L. IIl~, 84 Stat. 1883; 1!CC.4(a)
or Pub. L. IIl~, 1M Stat. 1887: IleC. 2 of Pub.
L. No. 110-148 81 Stat. 504 (42 U.s.C. 1857c~,
1857c-9, 1857g(a)).)
(Fa Doc.77-14562 PlIed 5-20-77;8:45 am]
FEDERAL IEGISnl, VOL 42, NO. "~ONDAY, MAY 23, 1977
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MONDAY, DECEMBER 5, 1977
PART II
ENVIRONMENT AL
PROTECTION
AGENCY
.
OPACITY PROVISIONS
FOR FOSSIL -FUEL -FIRED
STEAM GENERATORS
Revision of Format and Reporting
Requirements
91
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[6560-01 ]
Title ~8Ctlon of Environment
CHAPTER I-£NVIRONMENTAL
PROTEcnON AGENCY
",U8CHAP'TU ~II' I'ROGItAM'
IPRL803-a'
PART ~STANDARDS Of PERfORM-
ANCE fOR NEW STATIONARY SOURCES
Opacity Provisions for fossll-fuel.Flred
Stum Gell8nltors
AGENCY: EnYtronmental Protection
,\&ency IEPA).
ACTION: Pinal rule.
SUMMARY: ThI.s role rev1ses the format
of the opacity standard and establ1ahes
reporunc requirements for exce81 emil-
slona of oP8Clty for fossU-fuel-fired
steam cenerators. Thla action Ia needed
to make the standard and reporunC re-
quirements conform to chanles In the
Reference Method for determlnlnc opac-
ItY which were promuipted on Novem-
ber 12, 1874, (38 Fa 39872). The in-
tended etrect Ia to l1m1t opacity of emlB-
slona In order to lDIure proper operation
and maintenance of facUlties subject to
standards of performance.
El"P'ECT1VE DATE: '1"hb role Ia e1rectlve
on December 5, 1877.
ADDRESSES: A summa". of the public
comments received on the september 10,
1975 (40 Fa 42028), pro:JQMd role with
EPA's responses Ia available for pUbl1c
inspection and copylnl at the EPA Pub-
I1c Information Reference U11It (EPA
1Jbrary), room 2822, 401 M Street SW.,
Washincton, D.C. 20480. In addItion,
copies of the comment summary may be
obtained by wr1t1nc to the EPA Publ1c
InfomiaUon Center (PM-2l5). Washing-
ton, D.C. 20480 (speclty: "Public Com-
ment Summary: Steam Generator Opac-
Ity Exception (40 Fa 42028) H),
JI'OR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Director, Emission
Standards and Enelneerlnc Dlvlalon
IMD-13) , Environmental Protection
Alency, Research Trlanlle Park. N.C.
27711, telephone: 919-541-5271.
SUPPLEMENTARY INFORMATION:
The standards of performance for fossU-
fuel-nred steam cenerators as promul-
lated under Subpart D of Part 80 In De-
cember 23. 1971, 138 FR 24378) allow
emlaslons up to 20 percent opacity, ex-
oept 40 percent Is aUowed for two minutes
In any hour. On October 15. 1973, 138
FR 28564) a prov1slon was added to Sub-
pI" D which requlred reporunl as excel8
ea. ;10118 aU hourly periods durlnc
who I there were three or more one-
mint te periods when average opacity
exce~ds 20 percent. Chanles to the opa-
city provlslona of Subpart A, General
Provisions. and to Reference Method 9.
Visual Determination of the Opacity of
Emwlona from Stationary Sources, were
promulilted on November 12, 1974 139
RULES AND REGULATIONS
Fa 398721. Arnone these chances Is a
requirement. that opacity be determined
by averaC1nc 24 readlncs taken at 15-
second Intervals. Because of thIa chance,
the Acency reassessed the opacity stand-
ard orlC1nally promulgated under Sub-
part D, and on September 10, 1875, pro-
posed amendments to the opacity stand-
ard and reporunl requirements. Speclfi-
ca11y. these amendments would have de-
leted the pennla81ble exemption (t-
minutes per hour of emlsalons of 40 per-
cent opacity) for caseoua and IOl1d foull
fuela.
The proposed amendment to the opac-
Ity provlalona wu based on a reY1ew of
available data particularly with respect
to the challeD8e to the opacity standards
for coal.ftred steam generators (Es,ez
Chnnlclll Corp. d Ill. Y. RlICtelshGtU, Ap-
palAchian POV1C' Co.. d Ill. VB. EPA. 488
P.2d 427, September 10. 19731. Informa-
tion available at that time indIcated that
the two-minute exception allowed under
I 60.42(a) (2) wu unnecessary for larce
steam cenerators ftred with solid and
caseous foull fuela.
Interested parties were lnY1ted to aub-
mlt comments. A total of 10 Interested
partlea, 1nc1ud1JW State apnclea, electrtc
uWlty ftrms, and industrial ftnns sub-
mitted comments. Pollowm. a reY1ew of
the propoBed amendments aDd eonsld-
eration of the comm~nts, the amend-
menta have been rev1sed and are belD8
promullated today.
While DO information was aublrJtted
to show that the exception' Ia needed for
larce utility ste.am ceneratGrs equipped
with conventional "cold sMe" electro..
static precipitators or with scrubbers alP.'
fabric flJters, commenter. contended
that the t1to-mlnute exception Ia needed
for Industrial boilers and for au units
equipped with so-called "hot side" ell'C"...
tl'OlltaUc precipitators, 220 MW heat Input) that
are not equlpped with hot aide precipita-
tors, but &c&In the deletion would have
little e1rect and would needleuly compl1-
cate the rqulaUon.
Section 80.42(a) (2) Ia amended by ex-
preaslnc the two-minute 40 percent
opacity exception In terms of a six-min-
ute 2'7 percent averap opacity (a
welchted average of two minutes at 40
percent opacity and four minutes at 20
percent opacity) for cOnal8tency with
Reference Method 9. Thla chance does
not alter the 8trtncency of the standard.
In addItion, 160.45(1) (1) which wu re-
served on October 8, 1975., (40 Fa 48250)
pendlnC reaolutlon of the opacity ex-
ception, 18 added to require reportlnc as
excess emla810na any alx-mlnute period
durlnl which the averace opacity of
emlasiona exceeda 20 percent opacity, ex-
cept for the one permla81ble six-minute
period SOU bour of up to 27 percent
opacity,
Nan:.-Th. Environmental Protec:tion
Ac.nCJ bu d.termlned that thl.
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31514
Federal Register I Vol. 44. No. 106 I Thursday. May 31. 1979 I Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 761
(FRL 1075-2]
Polychlorinated Biphenyls (PCBs)
Manufacturing, Proc888lng,
Distribution in Commerce, and Use
Prohibitions
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This final rule implements
provisions of the toxic Substances
Control Act (TSCA) prohibiting the
manufacture. processing. distribution in
commerce. and use of polychlorinated
biphenyls (PCBs). Specifically. this rule:
(1) Prohibits all manufacturing of
PCBs after July Z. 1979 unJess
specifically exempted by the
Environmental Protection Agency (EPA):
(2) Prohibits the proceuing,
distribution in commerce. and use of
PCBs except in a totally.enclosed
manner after July Z. 1979:
(3) Authorizes certain proceuing.
distribution in commerce. and use of
PCBs in a non-totally enclosed manner
(which would otherwise be subject to
the prohibition described above);
(4) Prohibits all processing and
distribution in commerce of PCBs after
July 1. 1979. unJess specifically
exempted by EPA.
EFFEcnVE DAn: July Z. 1979. The disposaJ
and marking rule (43 FR 7150. February
17. 1978. as amended by 43 FR 33918
August Z. 1978) shall remain in effect
until the rule promulgated today
becomes effective.
FOR FURTHER INFORMATION CONTAC'r.
For information concerning this rule and
for copies of this rule contact John
Ritch. Jr" Director. Office of Industry
Assistance. Office of Toxic Substances
(TS-799). EnvironmentaJ Protection
Agency. 401 M Street. S.W"
Washington. D.C. 20460. Call Ibe toll-
free number (800)-424-9065. or in
Washington. D.C. call 554-1404.
The support documentation for this
rule can also be obtained through the
above-mentioned addreu. The support
documentation consists of two parts and
are entitled Support Document/
Voluntary Environmental Impact
Statement and PCB Manufacturing.
Processing. Distribution in Commerce
Ban Regulation: Economic Impact
Analysis. (This Economic Impact
Analysis is hereinafter referred to as the
Versar Report). These two documents
have been reproduced and bound into
one publication.
SUPPLEMENTARY INFORMATION:
Format of Rule
In order to clarify the relationship
between the PCB Disposal and Marking
Rule and the PCB Ban Rule. all of Part
761 is printed in this notice in a ful]y
integrated form. This notice incorporates
the Disposal and Marking Rule (43 FR
7150. February 17. 1978) for PCBs and
the technical amendments (43 FR 33918.
August 2. 1978) to that Rule into one
regulation. Therefore. this notice
supercedes the previous hotices on July
Z. 1979.
Background
Section 6(e) of TSCA requires EPA to
control the manufacture. processing,
distribution in commerce. use. disposal.
and marking of polychlorinated
biphenyls (PCBs). On February 17. 1978.
EPA published the PCB DisposaJ and
Marking Rule in the FederaJ Regiater (43
FR 7150). Clarifying amendments to this
rule were published on August Z. 1978
(43 FR 33918).
Section 6(e)(2) provides that no person
may manufacture. process. distribute In
commerce. or use any PCB in a manner
other than In a "totally enclosed
manner" after-January 1. 1978. except to
the extent EP A authorizes activities In a
non-totally enclosed manner. On
December 30.1977. EPA published a
notice (42 FR 85264) eta!ins that
implementation-of the January 1. 1978
ban would be postponed until 30 days
after promulga tion of thie rule.
Section 6(e)(3) providee that no person
may manufacture any PCB after January
1. 1979. or process or distribute In
commerce any PCB after July 1. 1979.
except to the extent that EPA
specifically exempts euch activities.
lmplementll.tion of the January 1. 1979
ban was postponed until 30 days after
the promulga tion of the rule published
today (See 44 FR 108. January z. 1979).
Section 6(e)(3)(B) provides that
persons may petition the Administrator
for exemptions from the prohibition of
the manufacture of PCBs. which goes
into effect July Z. 1979 or from the
prohibition of processing and
distribution in commerce. which goes
into effect July 1. 1979. Interim rules
establishing procedures for submitting
petitione for i!xemptions from the
manufacturing prohibition were
published November 1.1978 (43 FR
50905). More than 70 petitions for
exemptions have been received. On
January 2.1979. EPA announced (44 FR
108) that it would not enforce the PCB
manufacturing and importation ban of
9~
section 6(e)(3)(A) against persons who
had submitted petitions until EPA has
acted on their exemption petition. This
nonenforcement policy applies solely to
activities that are properly subject to a
pending PCB manufacturing or
importation exemption petition.
Elsewhere in today's Federal Register.
EPA has published a Notice of Proposed
Rulemaking that identifies each petition
received for exemptions from the
manufacturing prohibition and. in most
cases. the action that EPA proposes to
take on individual petitions. Rules
establishing procedures for submitting
petitions for exemptions from the
processing and distribution in commerce
prohibitions will be published in the
near future.
Authority to grant or deny petitions
for exemptions from the PCB processing
and distribution in commerce bans
under. section 6(e)(3)(8) of TSCA. as well
as the authority to revise the procedural
rules for PCB exemptions and to grant
further PCB authorizations and to
amend or modify this regulation is
delegated to the Assistant Administrator
f,!1r Toxic Substances. This authority
was previously delegated to the
Assistant Administrator for Toxic
Substances for the PCB manufacturing
exemptions (see 43 FR 50905).
This finaJ rule implementing sections
6(e) (2) and (3) of TSCA was proposed
June 7. 1978 (43 FR 24802). Ten days of
public hearings were held In
WaehiDgton. D.C" from August 21 to
September 1. Over 50 oral presentations
were made and two hearing participants
conducted cross-examination on
September 26. 1978. On September 2Z.
1978 (43 FR 43048). EPA published a
notice of the opportunity for cross-
examination and extended the reply
comment period to October 10. 1978.
EPA received over 200 comments on the
proposed rule.
EPA has produced. as part of the
rulemaking process for PCBs. two
support documents. The first support
document which was entitled Support
Document/Voluntary Draft
Environmental Impact Statement. was
made available at the time the proposed
rule was published and discussed the
health and environmental effects of
PCBs. the substitutes for PCBs. and the
regulatory alternatives EPA considered
in developing the proposed PCB Ban
Rule. The second support document
entitled Support Document/Voluntary
Environmental Impact Statement was
prepared along with the final PCB Rule
and Preamble. This particular document
contains updated versions of the health
and environmental effects and PCB
substitutes sections. and addresses the
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Federal Regiater I VoL 44. No. 106 I Thunday, May 31. 1979 I Rules and RegulatioD8
31515
major comments that were made on the
propoaed rule during the comment
period. In many caaea theae comments
led to changes to the propoaed PCB Ban
Rule. There are also two versiona of the
economic impact analyaia that have
been prepared by Venar.Inc. The first
Versar Report waa made available at
the time of the propo&ed PCB Ban Rule.
The second. or final Venar Report. hu
been incorporated inlO the final Support
DocumenL Copies of the final Support
Document can be obtained from the
Induatry Anialance Office identified
above.
Tab18 1~_" of "-1118
I. Summuy of the Rula'a Orwllliuliaa
n. Chugel in Major DeflDiliou
A. "PCB" and "PCB It_"
B. RepJaUoa of PCBI al tha 50 ppm
ConcentraUoa Level
C. Clallmeelion of Trulaformva Uad8r
ThiaRuie
1. PCB Trmaformera
2. PCB-Conl8llliDated Tru8formen
3. Non-PCB Tnnaformera
4. DilCU88iDD of Tl'8II8fonlW' Caf880ria8
a. DetermiIIiDI AJllll'llPriate Caleaori".
b. SipliflC8DC8 of Traaaformar Cal8lJOne.
D. TOlally EadOlld MaDDar and SipifiCUI
Expo.we
E. Sale for Purpo... Other 11wI Reaale
F. Other DeliDilioDi.
W. Ch8l\ll' in Subpart B: Di.poaai of PC8a
and PCB lIema
A. Mineral Oil Dielectric Fluid with 50 10
500 ppm PCB
1. Hiab Efficiency Boilera
Z. Condi tion. for Bollera
3. Other Di.po.al AltemaUve.
B. Other Liquid Wula. with 50 10 500 ppm
PCB
C. Di.po.ai of 50 to SOO ppm PCB Liquid! ill
Chemll:arWule Landfill.
D. Di.po'" of Noa-Liquid PCBIIa
Chemical Wa.te Landfilla
E. Batch Te'liD8 of Mineral Oil Dielectric
Fluid
F. Other Chugll ill the DI.po'"
Requiremenll
IV. Chanll8l in Subpart C: MarIcin& of PC8a
and PCB Item.
V. Change. Ia Subpart E: Annexe.
A. Annex I: Incinention
B. Annex U: Chemical Wa.te Landfill8
C. Annex ill: Storage
1. Conlainer SpecifieeUona
2. Bulk Stonp
3. Spill Prevention Procedure.
4. Flood Protection
5. Temporuy Slor..e
8. Revi.ion.
b. Action on PetilioDi to Amend Rule on
Tempor.ry Stonge Requirement.
D. Annex IV: Decontamination
E. Annex VI: Record. and'Monitoring
VI. Subpart D: M8nufacturill3. Proce.llDg.
Distribution in Commerce. and U.e Bana
A. Prohibitions
1. Waste Oil Bani
B. Chang!!'. .n t i81.3O: Proh,b:tiun.
1. Chang!!' ID Scope of Manufacturina B~n
.. "\'tanufactunna" versu, "Proceiling of
PCB Heml
b. Manufactun and Import of PCB ltelD8
2. Import and Export of PCB. and PCB Item.
for Dilpo.ai
C. Other Illue.
L PCB ImPurilie. and Byproduct.
2. Dilpo'" of Sma!} PCB Capacitora
3. State Pr88mplion.
94
VD. Relallonabip oll8(a)(%110 1 8(e)(3) Ia
TSCA
vm. AulbDriMliGa8 md Bx8IplioD.8
A. Explaalloll of AuIhorialiou 8DcI
Bx8IpIiqaa
1. ManufectariD8 Bxemptkm8
Z. Proceeeine 8DcI Dtalributloa Ia CoIIIm8Ice
ExempllOU
&. General CIwIan Ia 1 7111.31:
AutbariulioD.8
1. RepoI1iq md Recordkeepiq
Raqu\mDeD1I
Z. L8natb of U.. Authnriulloll8
3. CIwIan Ia 1 781.48: An8x VB
IX. SpecifIc Authoriuliou
A. SemciD& 1'I8D.8formera (Other 11wI
Railroed 1'r8D8fonnen)
L c-.l Dlac:ua8ioa of Tnnefonner
ServlciD&
z.PCB~
3. fICB.Conl8miDated 1'r8D8bmen
4. Rebuildiaa PCB Trulaformen
S. Coalenll of Allthorialion
B. U.. and Servicin8 of RailroaIt
Trmaformera
C. U.. 8Dd Servlc:iD8 of MiIIins Equip_t
D. U.. In He.t 1'r8D8fer SYltema
E. U.. In Hydraulic SYlI8m8
P. U.. Ia CarboaIe.. Copy Paper
G. P\1JIII8Dtl
H. U.. and SemcIaa of Elec:tromagneta
L U.. ill Nelllr8l Gu PIpeline Compr81lOra
J. U.. of Small QuanUU.. for R88ean:b ud
Devalopmenl
K. Ulela Mlcroacopy
X. PCB AcllvlUea Nol Authorized by tbi8 Rule
A. Menuf.ctunt of PCB Capecilora
B. Manufactun of PCB Tran.formera
C. Other PCB Actlvllill
XL ManufacluriJl&, Procn8inll. and
DI.tribulion Ia Commerce of PCB. for
Export
XII. Tnt Procedurn for PCB
XlII Compliance and Enforcement
XIV' RelatioDlblp of PCB DI.po.ai Under
T5cA to Hazardoua Wa.te Di.po..l Under
RCRA
XV. Summery of EcoDomic COIIMquence.
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31518
Federal Register I Vol. 44. No. 106 I Thursday. May 31. 1979 I Rules and Regulations
31519
m. Chang" in Subpart B: Disposal 01
PCB. and PCB ltema
A. Mineral Dil Dielectric Fluid With 50
to 500 ppm PCB
The proposed rule would have
changed the PCB Disposal and Marking
Rule by requiring all PCBs containing 50
ppm or more PCB to be disposed 01 in an
incinerator meeting the requirements of
Annex I. This requirement would have
increased the quantity of liquid to he
incinerated over the next 30 to 4() years
from 300 million pounds to at least 3
billion pounds. with proportional
increases in costs (see the Versar
Report). This increase would also have
severely strained available incineration
capacity. EPA was concerned about the
impact of this requirement and
requested comments on the use of high
temperature boilers for incinerating PCB
contaminated mineral oil.
1. High Efficiency Boilers
A substantial number of comments
stated that power generation facilities
could provide an environmentally safe
alternative for burning PCB-
contaminated mineral oil. EPA reviewed
the comments and investigated the
feasibility of permitting the use of
boilers as a disposal option. After
exploring this matter with combustion
experts. EPA concluded that there are
boilers capable of adequately
incinerating PCB-contaminated mineral
oil. These boilers (which can be referred
to as "high efficiency boilers") include
power generation boilers and industrial
boilers that operate at a high
combustion efficiency (99.9'J6), as
defined by the carbon monoxide-
concentrations and excess oxygen
percentages in the combustion
emissions.
These boilers are capable of achieving
a PCB destruction efficiency of 99.9'J6 or
greater. This destruction efficiency is
somewhat lower than the estimated
99.9999% or greater destruction
efficiency that an Annex I incinerator
can achieve. However. this disposal
alternative is restricted to PCB-
contaminated mineral oil of low PCB
concentration (50-S00 ppm) and offers a
substantial reduction in disposal costs
(over $13 million per year). Given the
99.9% destruction efficiency for PCBs in
high efficiency boilers. only 10 more
pounds of PCB would enter the
environment annually as compared to
the amount released from high
temperature incinerators under Annex L
(This estimate is derived-from Versar
data).
After considering these factors. EPA
concluded that disposing of PCB- -
contaminated mineral oil containing 50
to 500 ppm PCB in high efficiency boilers
does not present an unreasonable risk to
human health or the environment.
However. for the reasons explained in
section m.B. only PCB-contaminated
mineral oil will be permitted to be
burned in boilers without specific
approval by the appropriate EPA
Regional Administrator. A discussion of
the burning of other low concentration
PCB wastes also is found in section m.B.
2. Conditions for Boilers
Based on the conclusions stated
above. the final rule permit! the burning
of PCB-contaminated mineral oil with a
concentration below 500 ppm in high
efficiency boilers if the following
conditions are met: (1) the boiler is rated
at a minimum of 50 million BTU/hour:
(2) the mineral oil is no more than ten
percent of the total fuel feed rate; (3) the
mineral oil is not added to the
combustion chamber during boiler start-
up or shut-down operations; (4) before
commencing the burning of PCB-
contaminated mineral oil. the owner or
operator has conducted tests and
determined that the combustion
emissions contain at least three percent
(3%) excess oxygen and the carbon
monoxide concentration does not
exceed 50 ppm for oil or gas-fired boilers
or 100 ppm for coal-fired boilers; (5) the
company has notified the appropriate
EPA Regional Administrator at least 30
days before the company uses its high
efficiency boiler for this purpose and
has supplied the notice with the
combuation emiasions data as specified
in (4) above: (6) the combustion procesl
is monitored either continuously or. for
boilers burning less than 30.000 gallons
of mineral oil annually, at least once
each hour that PCB-contaminated
mineral oil is burned. to determine the
percentage of excess oxygen and_the
carbon monoxide level in the
combustion emission: (7) the primary
fuel and mineral oil feed rates are
monitored at least every 15 minutes
whenever burning PCB-a>ntaminated
mineral oil; (8) the carbon monoxide and
excess oxygen levels are checked at
least once an hour and. if they fall
below the specified levels. the flow of
mineral oil to the boiler is immediately
stopped; and (9) recorda are maintained
that include the monitoring data in (6)
and (7) above and the quantities of PCB-
contaminated mineral oil burned each
month. When burning mineral oil
dielectric fluid. the boiler mU8t operate
at a level of output DO less than the
output at which the reported carbon
95
monoxide and excess oxygen
measurements were taken. The Regional
Administrator has to be notified only
before the first burning of PCB-
contaminated mineral oil in the boiler.
The conditions al'J! intended to prevent
the introduction of PCBs into boilers
when combustion conditions are not
optimum for the destruction of PCBs.
The level of 30.000 gallons per year was
chosen as the cut-off for continuous
monitoring because. (1) EPA believes
that boilers burning 30.000 gallons or
more per year of PCB-contaminated
mineral oil would be burning on a
regular basis and therefore should
continuously monitor CO and excess 0.;
and (2) a boiler burning this quantity of
mineral oil annually will incur more
than sufficient savings over high
temperature incineration or chemical
waste landfill disposal costs to offset
the added costs of continuous
monitoring. However. a person whose
boiler does not meet these requirements
but who can demonstrate that the boiler
will destroy PCBs as efficiently as a high
efficiency boiler may seek specific
approval from the appropriate EPA
Regional Administrator under
~ 761.10(a)(2)(iv).
EPA plans to monitor the use of these
boilers closely and will carefully
analyze the effectiveness of this
disposal option.
3. Other Disposal Alternatives
Alternatively. any PClkontaminated
mineral oil dielectric fluid (with a PCB
concentration less than 500 ppm) may be
disposed of either in an incinerator
complying with Annex lor. under
special conditions (see section UI.C
below). in a chemical waste landfill
complying with Annex U. These landfills
will provide a disposal option less costly
than Annex I incineration for owners or
users of PCB-contaminated mineral oil
who do not have access to high
efficiency boilers. EPA believes that
only small quantities of dielectric fluid
will be disposed of in landfills because
high efficiency boilers or incinera tors
will be available for most of the waste
fluids.
The impact on human health and the
environment from disposing of these
wastes in chemical waste landfills is
discussed in the preamble section lII.B
below.
B. Other Liquid Wastes With 50 to 500
ppm PCB
To provide thermal destruction
altematives for other low concentration
liquid wastes containing less than 500
ppm PCB. EPA has included in the rule a
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31519
Federal Register I Vol. 44, No. 106 I Thursday, May 31, 1979 I Rules and Regulations -
31520
procedure that i. comparable to the
disposal alternative. for PCB-
contaminated miDeral oil. ThiJ
procedure permits the disposal of these
non-miDeral oil fluids on a case-by-case
basis in high efficiency boilers.
Such approval can be granted if: (1)
the boiler is rated at a minimum of 50
million BTIJ/hour: (2) the PCB-
contaminated waste comprises no more
than ten percent (1D") of the total
volume of fuel: (3) the waste will not be
added to the combuation chamber
during boiler start-up or shut-down
operations: (4) the combustion emissions
will contain at I.ast three percent (3%)
excess oxygen and the carbon monoxide
concentration will be le5s than 50 ppm
for oil or gas-rued boilers or 100 ppm for
coal-rued boilers: (5) the combustion
process will be monitored continuously
or at least once each hour that the PCB-
contaminated wastes are being burned
to determine the percentage of excess
oxygen and the carbon monoxide level
in the combustion emissions: (6) the
pnmary fuel and waste feed rates are
monitored at least every 15 minutes
whenever burning the waste; (7) the
carbon monoxide and excess oxygen
levels are monitored at least once an
hour and if thev fall below the levels
specified. the flow of wastes to the
boiler is stopped immediately; and (8)
records are maintained that include the
monitoring data in (5) and (6) above and
the quantities of PCB-contaminated
waste burned each month. When
burning PCB wastes. the boiler must
operate at a level of output no less than
the output at which the reported carbon
monoxide and exce.. oxygen
measurements were taken. These
requirements are similar to thole for
high efficiency boilers uaed to bum PCB-
contaminated mineral oil.
Persona seeking approval to use this
disposal alternative must submit an
application to the appropriate EPA
Regional Administrator. The .ppUcation
must contain information describm, the
quantity of waste expected to be
dispoled of each month. descriptive
information about the waste including
the concentrations of PCBs and other
chlorinated hydrocarbons. the results of
a number of standard fuel analyses to
determine the nature of the waste, B1U
beat value and flash point of the wastes,
and an explanation of the procedures to
be followed to insure tbat burning the
waste in the boiler will not adversely
affect the operation of the boller.uch
that the combustion efficiency will
decrea... The information contained In
the applications will help the Regional
Administrator to asse.. whether these
high efficiency boilers will adequately
96
destroy these low concentration PCB
wastes.
The cost of this alternative 18 greater
than the mineral oil disposal altemativt
because approval8pplication cos~ and
analytical costs are greater. However.
these costs will be Ie.. than the cost for
Annex I Incineration or Annex 0
chemical waste landfills. AI a result. the
quantity of Iqw conceptraUon pCB
wastes goinl to Annex I and Annex 0
facilities should be reduced. In addition.
a person whose boiler does not meet
these requirements but who can
demonstrate that the boiler will destroy
PCBs as efficiently 81 a high efficiency
boiler may seek specific approval &om
the appropriate EPA Regional
Administrator under I 761.10(a)(3)(lv).
These wastes are treated diHerently
than PCB-contaminated mineral 011
dielectric fluid because they tend to be
more varied in composition than
contaminated mineral oil In many
cases, these fluids are fire or heat
resistant and could reduce PCB
destruction efficiency. For example,
unlike mineral oil. PCB-contaminated
hydraulic fluid will require the addition
of more primary fuel for it to burn in the
manner necessary to destroy the PCBs.
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31522
Federal Register I Vol. 44. No. 106 I Thursday. May 31. 1979 I Rules and Regulations
V. Changes 10 SubpllJ't E: Annexes
A.. Annex I: Incineration
Section 761.4O(a)(2) establishes a new
value of 99.9% for the combustion
efficiency required of incinerators. This
is a correction of the earlier value of 99%
efficiency that was specified in the
Disposal and Marking Rule. Specifically.
Incmerators operating at the
temperatures. dwell times. and excess
oxygen concen~ations specified in
Annex I normaUy operate IW a
combustion efficiency of 99.9% or
greater. A combustion efficiency of
99.9% thus more accurately represents
the true combustion efficiency of Annex
I incinerators. All incinerators that have
been approved or that are under "
consideration for approval by EPA are
capable of operating at 99.9%
combustion efficiency: accordingly. this
modification should not disqualify these
incinerators or result in additional
operating expenses for these facilities.
(This change does not mean that those
incinerators already approved will be
required to reat:ply for approval to
operate.) Combustion efficiency is an
effective parameter for evaluating the
degree of destruction that occurs in an
incinerator. and it is essential that the
required value for this parameter
accurately reflect expected combustion
conditions.
A change has heen made to the Co.
monitoring requirement of 1 761.4O(a)(7).
The Disposal-and Marking Rule required
continuous monitoring of the CO.
concentration in the stack gas of the
incinerator.1be rule has been changed
to require periodic CO. monitoring ai
specified by the Regional Administrator.
This change was made for two reasons:
(1) the high cost of the equipment
needeii to continuously monitor CO.;
and (2) the insensitivity of the
combustion efficiency calculation to
variations in the CO. concentration.
-The automatic shutoff of waste flow
that was required by the Dilposal and
Marking Rule when ce,rtain operating
deficiencies occurred has been modified.
Owners or operators of an incinerator
may submit to the Regional /
Administrator. when they apply for the
approval to incinerate PCBs. a
contingency plan outlining the corrective
steps they will take when operating
problems occur. This change provides
for greater flexibility for incinerator
operators and will result in no increased
human or environmental exposure since
the contingency plans will be examined
on a case-by-case basis by the Regional
Administrator for proper safeguards
before approval.
A new paragraph. 1 761.4O(d)(6). has
been added to clarify the responsibility
of the owner or operator of an approved
facility when the ownership of the
facility is transferred.
B. Annex II: Chemical Waste Landfills
Section 761.41(b) specifies
requirements for operational plans for
chemical waste landfills. These
requirements have been modified to
require delineation of the procedures to
be used for the disposal of liquids
containing between 50 ppm and 500 ppm
PCB. After EPA approves an operational
plan. the affected landfill operator must
follow those procedures in disposing of
PCB wastes.
Section 761.41(b)(3) specifies that the
bottom of a chemical waste landfill must
be at least fifty feet above the historical
high water table. Because the distance
between the bottom of the chemical
waste landfill and the water table in
many areas east of the Mississippi River
is far less than fifty feet. EPA Regional
Administrators have had to waive this
criterion in several situations. While the
criterion in the final rule is uncha~ed
97
from the Disposal and Marking Rule.
EPA is proposing a modification of this
provision in a separate notice of
proposed rulemaking.
The provisions in Annex II of the
Disposal and Marking Rule.estabhshm8
monitoring requirements for surface
water (I 761.41(b)(6)(i)) have been
modified to allow the Regional
Administrator to designate the surface
watercourses that are to be sampled.
This minor change eliminates any
uncertainty about which watercourses
are to be sampled.
Section 761.41(b)(7) includes
provisions for leacha te collection in
chemical waste landfills. The Disposal
and Marking Rule specified that the
collection system be located under the
landfill liner system. The final rule
corrects this provision and specifies tha t
the collection system be above the
landfill liner system. Collection systems
are placed above the liner to capture
liquids to protect and reduce hydraulic
pressure on the liner system. All
chemical waste landfills currently in use
have collection systems above the liner.
A new paragraph. 1 761.41(c)(7). has
been added to clarify the responsibility
of the owner or operator of an approved
facility when the ownership of the
facility is transferred.
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Federal Register I Vol. 44. No. 106 I Thursday, May 31, 1979 I Rules and Regulations
31545
Subp8lt B-Oiapoul of PCB. .nd PCB
Item.
Nol..-ThlI Subpart don nOlrequiJ'e
rwmoval of PCBe and PCB lteml from 88mc:e
and diapoaal earlier thm would normally be
the CAle, However. wheD PCBI md PCB
Iteml are removad from ..rvice aDd di.poeed
of. di.poI&I mual belllldertaku iA
accordanC8 with thel' resu!alioDi. PCB.
(IncludiDI loila and debnal aDd PCB Itema
which have been placed iA a dilpoaa! Iii. are
conl1dered 10 be "iD servic." for purpOI.. of
the applicability of !hi. Subpart. ThI. Subpart
does nol require PCB. aDd PCB Ileml
landfilled prior 10 February 17. 1978 10 be
rwmoved for dilpolaL However. if IUch PCB.
or PCB lIeml are removed from the dilpol&l
Slie. they mual be diapoaed of in accorclaDce
WIth tbJ. Subpart. Other Subparll are
directed 10 tha manatactura. proce..mg.
di.tnbubon in commelW. ud UN of PCBe
aDd may relull iA aoma ca... iD diapoaalal
aD earlier dala th8D would otherwiaa OCQlf.
f 781.10 DI8pouI requlr8ment8.
(a) PC&. (1) Except a. provided in
subparagraph. (2). (3). (4). and (5) of thiI
paragraph. PCBa musl be di.po.ed of in
an incinerator which compliea with
Annex L
(2) Mineral oil dielectric flwd from
PCB-Contaminated Transformers
containing a PCB concentration of 50
ppm or greater. but less than 500 ppm.
must be disposed of in one of the
followin8:
(i) In an incinerator that complies With
Annex II 761.40;
(ii)1n 8 chemical wasle landfill that
complies with Annex U I 761.41 if
information is provided to the owner or
operator of the chemical waste landfill
that shaWl that the mineral oil dielectric
nuid does not exceed SOO ppm PCB and
is not an ignitable waste as described in
, 761.41 (b) (8) (iii) of Annex 1l
(iii) In a high efficiency boiler
provided that:
(A) The boiler complies Wllh the
following criteria:
(1) The boiler is rated at a minimum of
50 million BTU bours;
(2) If the boiler uses natural gas or oil
as tho lrimary fuel. the carbon
monc de concentration in the slack il
SO ppm Jr less and the excess oxygen il
811e8.1 three (3) percenl when PCBs are
belDg burned:
(3) If the boiler u.es coal as the
pnmary fuel. the carbon monoxide
concentration in the slack I. 100 ppm or
le.s and the exce" oxygen I. allea.t
three (3) percent when PCBs are beU1g
burned:
(f) The mineral oil dielectric fluid
does not comprill more than ten (10)
percent (on a volume balis) of the total
fuel feed rate;
(S) The mineral oil dielectric fluid i8
not fed into the boiler unlesl the boiler
i. operating at ill normal operating
temperature (!hi. prohibit. feeding these
fluidl durin8 either .tart up or shut
down operetiona):
(8) The OWDer or operator of the
boiler.
(I) Continuously moniton and recorda
the carbon monoxide concentration and
exces. oxygen percentage in the stack
ga. while burning mineral oil dielectric
fluid: or
(ill If the boiler will bum less than
30.000 gallons of mineral oil dielectric
fluid per year. measures and recorda the
carboD monoxide concentretion and
exce.. oxygen pen:entaglt in the .tack
gal at regular intervall of no longer than
eo minutes while burning mineral oil
dielectric fluid.
(7) The primary fuel feed rates.
mineral oil dielectric fluid feed rates.
and total quantitie. of both primary fuel
and mineral oil dielectric fluid fed to the
boiler ant mee.ured and recorded at
regular intervell of no longer than 15
minutes while burning mineral oil
dielectric fluid.
(8) The cerbon monoxide
concentration and the exce.. oxygen
percentage are checked at leest once
every hour that mineral oil dielectric
fluid i. burned. If either measurement
falll below the level. .pec:ified in thil
rule. the flow of mineral oil dielectric
fluid to the boiler shall be stopped
Immediately.
(B) Thirty days before any person
burn. mineral oil dielectric fluid In the
boiler. the person gives written notice to
the EPA Regional Administretor for the
EPA Region in which the .boiler il
located and that the notice contain. the
following information:
(1) The name and addrell of the
owner or operator of the boiler and the
addrell of the boiler:
(2) The boiler ralilW in units of BTU t
hour.
(3) The carbon monoxide
concentration and the excell oxygen
percentage in the stack of the boiler
when it I. operated in a manner similar
to the manner in which it will be
operated wben mineral oil dielectric
nwd is burned: and
(4) The type of equipment. apparatus.
and procedures to be used to control the
feed of mineral oil dielectric fluid to the
boiler and to monitor and record the
carbon monoxide concentration and
excess oxygen percentage in the stack.
98
(C) When bumin8 mineral oil
dielectric fluid. the boiler mUit operate
at a level of output no leas than the
output .t which the meuurements
required UDder subparagraph (B)(3) wera
taken.
(D) Any penan burning mineral oil
dielectric Ouid in a boiler obtainl the
following inlormation and retaiDa the
inlormation for five yeen at the boiler
loea tion:
(1) The data required to be collected
UDder subparagrapha (A)(8) and (A)(7)
of this paragraph: and
(2) The quantity of minerel oil
dielectric fluid burned in the boiler each
month;
(Iv) In a facility that is approved in
accordance with 1 781.10(e). For the
purpole of burning minerel 011 dielectric
fluid. an applicant under 1 781.10(e)
must Ihow that hit combustion procell
destroy. PCBs a. efficiently a. does a
high efficiency boiler. as defined in
.ubparagraph (Iii), or an Annex I
approved incinerator.
(3) Liquidl. other than mineral oil
dielectric fluid. containing a PCB
concentretion of 50 ppm or greater. but
lesl than 500 ppm. shall be dispoled of:
(i) In.an incinerator which complies
with Annex. I;
(ii) In a chemical wa.te landfill which
complies with Annex 0 if information il
provided to the owner or operator of the
chemical wa.te landfill that sbows that
the waste does not exceed SOO ppm PCB
and i. not an ignitable waste as '
described in 1 781.41(b )(8')(iii)of Annex
D.
(iii) In a high efficiency boiler
provided that:
(AI The boilercompliea with the
following criteria:
[1) The boiler il rated at 8 minimum of
50 million BTU thour:
(2) If the boiler uses naturalgu or oil
al the primary fuel. the carbon
monoxide concentration in the stack il
50 ppm or lell and the exce.. oxygen is
at leut three (3) percent when PCB. ant
being burned:
(3) If the boiler uses coal as the
primary fuel. the carbon monoxide
concentration in the stack i.l00 ppm or
less and the exces. oxygen is at least
three (31 percent when PCB. are being
burned:
(4) The waste aoes not comprise more
than ten (10) percent (on e volume baail)
of the total fuel feed rate;
(51 The waste i. not fed into the boiler
unles. the boiler i. operating at ita
normal operating temperature (this
prohibit. feeding these fluidl during
either .tart up or shut down operation.):
(6) The owner or operator of the boiler
must:
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31546
Federal Register I Vol. 44. No. 106 I Thursday. May 31. 1979 I Rules and Regulations
(I) Continuously monitor and record
the carbon monoxide concentration and
excess oxygen percentage in the stack
gas while burning waste fluid: or
(iI) If the boiler will burn less than
30.000 gallons of waste fluid per year.
measure and record the carbon
monoxide concentration and excess
oxygen percentage in the stack gas at
regular intervals of no longer than 60
minutes while burning waste fluid:
(7) The primary fuel feed rate. waste
fluid feed rate. and total quantities of
both primary fuel and waste fluid fed to
the boiler mu.t be measured and
recorded at regular intervals of no
longer than 15 minutes while burning
waste fluid: and
(8) The carbon monoxide
concentration and the excess oxygen
percentage must be checked at least
once every hour that the waste is
burned. If either measurement falls
below the levels specified in this rule.
the flow of waste to the boiler shall be
stopped immediately.
(B) Prior to any person burning these
liquids in the boiler. approval must be
obtained from the EPA Regional
Administrator for the EPA Region In
which the boiler is located and any
persons seeking such approval must
submit to the EPA Regional
Administrator a request containing at
least the following information:
(1) The name and address of the
owner or operator of the boiler and the
address of the boiler:
(2) The boiler rating in units ofJITUI
hour:
(3) The carbon monoxide
concentration and the excess oxygen
percentage in the stack of the boiler
when it is operated in a manner similar
to the manner in which it will be
operated when low concentration PCB
liquid is burned:
(4) The type of equipment. apparatus.
and procedures to be used to control the
feed of mineral oil dielectric fluid to the
boiler and to monitor and record the
carbon monoxide concentration and
excess oxygen percentage in the stack;
(5) The type of waste to be burned
(e.g.. hydraulic fluid. contaminated fuel
oil. heat transfer fluid. etc.):
(6) The concentration of PCBs and of
any other chlorinated hydrocarbon In
the waste and the results of analyses
using the American Society of Testing
and Materials (ASTM) methods as
referenced below: carbon and hydrogen
content using ASTM 0-3178. nitrogen
content using ASTM E-258. sulfur
content using ASTM D-2784. D-1286. or
D-129. chlorine content using ASTM D-
808. water and sediment content using
either ASTM D-2709 or D-1796. ash
content using 0-482. calorific value
using ASTM D-240. carbon residue
using either ASTM D-2158 or D-524. and
flash point using ASTM D-93:
(7) The quantity of wastes estimated
to be burned in a thirty (30) day period:
(8) An explanation of the procedures
to be followed to insure that burning the
waste will not adversely affect the
operation of the boiler such that
combustion efficiency will decrease.
(C) On the basis of the information in
(B) above and any other available
information. the Regional Administrator
may. at his discretion. find that the
alternate disposal method will not
present an unreasonable risk of injury to
health or the environment and approve
the use of tile boiler:
(D) When burning PCB wastes. the
boiler must operate at a level of output
no less than the output at which the
measurements required under
subparagraph (B)(3) were taken: and
(E) Any person burning liquids in
boilers approved as provided in (C)
above. must obtain the following
information and retain the information
for five years at the boiler location:
(1) The data required to be collected
in subparagraphs (A)(6) and (A)(7) of
this paragraph:
(2) The quantity of low concentration
PCB liquid burned in the boiler each
month.
(3) Tbe analysis of the waste required
by subparagraph (B)(6) of this paragraph
taken once a month for each month
during which low concentration PCB
liquid is burned In the boiler.
(iv) In a facility that is approved In
accordance with I 781.10(e). For the
purpose of burning liquids. other than
mineral oil dielectric fluid. containing 50
ppm or greater PCB. but less than 500
ppm PCB. an applicant under I 781.10(e)
must show that his combustion process
destroys PCBs as efficiently as does a
high efficiency boiler. as defmed In
I 781.10(a)(2)(iii). or an Annex 1
incinerator.
(4) Any non-liquid PCBs in the form of
contaminated soil. rags. or other debris
shall be disposed of:
(i) In an incinerator which complies
with Annex I: or
(ii) In a chemical waste landfill which
complies with Annex n.
Note: Except as provided In
I 781.41(b)(8)lii). liquid PCBs shall not
be processed into non-liquid forms to
circumvent the high temperature
incineration requirements of 1 781.10(a).
(5) All dredged materials and
municipal sewage treatment sludges that
contain PCBs shall be disposed of:
(i) In an incinerator which complies
with Annex I:
99
(ii) In a chemical waste landfill which
complies with Annex II: or
(iii) Upon application. using a disposal
method to be approved by the Agency's
Regional Administrator in the EPA
Region in which the PCBs are located.
Applications for disposal in a manner
other than prescribed in (i) or (ii) above
must be made in writing to the Regional
Administrator. The application must
contain information that. based on
technical. environmental. and economic
considerations. indicates that disposal
in an incinerator or chemical waste
landfill is not reasonable and
appropriate. and that the alternate
disposal method will provide adequate
protection to health and the
environment. The Regional
Administrator may request other
. information that he or she believes to be
necessary for evaluation of the alternate
disposal method. Any approval by the
Regional Administrator shall be in
writing and may contain any
appropriate limitations on the approved
alternate method for disposal. In
addition to these regulations. the
Regional Administrator shall consider
other applicable Agency guidelines.
criteria. and regulations to ensure that
the discharges of dredged material and
sludges that contain PCBs and other
contaminants are adequately controlled
to protect the environment. The person
to whom such approval is issued must
comply with all limitations contained in
the approval.
(8) When storage is desired prior to
disposal. PCBs shall be stored in a
facility which complies with Annex W.
(b) PCB Articles. (1) Transformers. .
(i) PCB Transformers shall be
disposed of in accordance with either of
the following:
(A) In an incinerator that complies
with Annex I; or
(B) In a chemical waste landfill which
complies with Annex ll: provided that
the transformer is first 'drained of all
free flowing liquid. filled with solvent.
allowed to stand for at le&8t 18 hours.
and then drained thoroughly. PCB
liquids that are removed shall be
disposed of in accordance with
paragraph (a) of this section. Solvents
may include kerosene. xylene. toluene
and other solvents in which PCBs are
readily soluble. Precautionary measures
should be taken. however. that the
solvent flushing procedure is conducted
in accordance with applicable safety
and health standards as required by
Federal or State regulations.
(ii) PCB-Contaminated Transformers
shall be disposed of by draining all free
flowing liquid from the transformer and
disposing of the liquid in accordance
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Federal Register / Vol. 44, No. 106 / Thursday, May 31, 1979 J Rules and Regulations
31547
with paragraphs (a)(2) above. The
disposal of the drained transfonner is
not regulated by this rule.
(2) PCB Capacitors. (i) The disposal of
any capacitor normally used in
alternating current circuits shall comply
with all requirements of this subpart
unless it is known from label or
nameplate information, manufacturer'.
literature, or chemical analysis that the
capacitor doe. not contain PCBs.
(ii) Any person may di.po.e of PCB
Small Capacitors u municipal solid
waste, unless that person is subject to
the requiremenla of subparagraph (iv).
(iii) ADy PCB Large High or Low
Voltage Capacitor owned by any person
shall be disposed of in accordance with
el ther of the following:
(A) Disposal in an inCU1erator that
complies with Annex I; or
(H) Until January 1. 1980. disposal in.
chemical waste landfill that complie.
with Annex n.
(iv) Any PCB Small Capacitor owned
by any person who manufacture. or at
any lime manufactured PCB Capaciton
or PCB Equipment and acquired the PCB
Capacitors in the coune of such
manufacturing shall be dispo.ed of in
accordance with either of the followUJs:
(A) Disposal in an incinerator which
complies with Annex I: or
(B) Until January 1,1980. disposal in a
chelDlcal waste landfill which complies
with Annex 11.
(3) PCB Hydraulic Machines. PCB
hydraulic machine. such as die castins
machines may be disposed of as
municipal solid waste or salvage
provided that the machines are drained
of all free-flowing liquid and the liquid i.
disposed of in accordance with the
provl8lons of ~ 761.1O{a). If the PCB
liquid contains 1000 ppm PCB or greater.
then the hydraulic machine must be
flushed prior to disposal WIth a solvent
contauung less than 50 ppm PCB (see
transformer solvents at
~ 761.10(b)(1){i)(B)) and the solvent
disposed of in accordance wi th
~ 781.10(a).
(4) Other PCB Articles must be
disposed of:
(i) In an incinerator that complies with
Annex I: or
[ii) " a chemical waste landfill that
com I 's WIth Annex II, provided that
all fn flowing liquid PCBs have been
thOroUI 11y drained from any articles
before l.1e articles are placed in the
chenucal waste landfill and that the
drained liqwds are disposed of In an
llIcmerator that complies With Annex I.
(5) Storage of PCB Articles-Except
for II PCD Article descnbed in
3ubpdrulo:raph (bl[:!)(iI] Jnd hydraulic
machmes Ihdt comply wIth the
municipal solid waste disposal
provisions described in subparagraph
(b)(3). any PCB Article shall be stored in
accordance with Annex ill prior to
dispo.al.
(c) PCB Containe/"6. (1) UnJeSl
decontaminated in compliance with
Annex IV or as provided in (2) below, a
PCB Container shall be disposed of:
(i) In an incinerator which complies
with Annex I. or
(ii) In a chemical wa.te landfill that
complies with Annex 0; provided that if
there are PCBs in a liquid state. the PCB
Container shall rll'llt be drained and the
PCB liquid disposed of in accordance
with paragraph (a) of this section.
(2) Any PCB Container used to
contain only PCBs at a concentration
less than 500 ppm shall be di.poaed of
as municipal solid wastea: provided that
if the PCBa are in a liquid state. the PCB
Container shall first be drained and the
PCB'liquid shall be disposed of in
accordance with paragraph (a) of thia
section.
(3) Prior to di.po.al. a PCB container
shall be atored in a facility which
compliea with Annex m.
(d) Spills. (1) Spill. and other
uncontrolled discharaea of PCBs
constitute the dispo181 of PCBs.
(2) PCBs resulting from spill clean-up
and removal operationa shall be stored
and disposed of in accordance with
paragraph (a) of this section. In order to
detennine if a spill of PCBs has reaulted
in a contamination level that ia 50 ppm
of PCBs or greater in soil. gravel. sludge.
fill. rubble, or other land based
substances. the person who spilla PCBs
should,conault with the appropriate EPA
Regional Administrator to obtain
infonnation on sampling methoda and
analytical procedures for determining
the PCB contamination level allociated
with the spill.
(3) This paragraph does not exempt
any person from any action. or liability
under other statutory authorities.
including seclion 311 of the Clean Water
Act and the Resource Conservation and
Recovery Act.
(e) Any person who is required to
incinerate any PCBs and PCB Items
under this subpart and who can
demonstrate that an alternative method
of destroying PCBs and PCB Items exisll
and that this alternative method can
achieve a level of perfonnance
equivalent to Annex I incinerators or
high efficiency boilers as provided in
~ 761.10(a)(2)(iv) and t 761.10(a)(3)(iv),
may submit a wntten request to the
Regional Administrator for an
exemption from the incineration
requirements of AMex I. The applicant
must show that his method of destroYlDg
100
PCBs will not present an unreasonable
risk of injury to health or the
environment. On the basis of such
information and any available
information. the Regional Administrator
may. in his discretion. approve the use
of the alternate if he fmdl that the
alternate dispo.al method provides PCB
destruction equivalent to disposal in an
Annex 1 incinerator and will not present
an unrealonable risk of injury to health
or the environment. Any approval mUit
be stated in writing and may contain
such conditionl and provisions as Ihe
Regional Adminiltralor deeml
appropriate. The person to whom such
waiver i. iuued must comply with all
limitations contained in such
determination.
(0(1) Each operator of a chemical
waste landfill. incinerator, or alternative
to incineration approved undt!'
paragraph Ie) shall give the following
written notice. to the state and local
governmentl within whose jurisdictiQn
the dispow facility is located:
(i) Notice at leaat thirty (30) days
before a facility ia first used for disposal
of PCBs required by these regulations:
and
(ii) At the request of any state or local
governmant. annual notice of the
quantities and general description of
PCBs dispo.ed of during the year. This
aMual notice shall be given no more
than thirty (30) days after the end of the
year covered.
(2) ADy persOD who disposes of PCBs
under.. t781.10(a)(5)(iii) incineration or
chemical waste laDdfilling waiver shall
give written notice atlea.t thirty (30)
days prior to conducting the disposal
activities to the state and local
governments within whose jurisdiction
the disposal i~ to take place.
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101
... ~,
Monday
June 11, 1979
Part II
Environmental
Protection Agency
New Stationary Sources Performance
Standards; Electric Utility Steam
Generating Units
-------
33580
Federal Register I Vol. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
(FRl124D-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.). particulate matter. and
nitro!!en oxides (NO.) from new.
modified. and reconstructed electric
utility steam generating units capable of
com busting 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
sta tionary sources. The intended effect
of this regula tion is to require new.
modified. and reconstructed electric
utility steam generating units to use the
best demonstrated techno]ogical .ystem
of continuous emillion reduction and to
satisfy the requirements of the Clean Air
Act Amendment. of 1977.
DATES: The effective date of this
regulation is June 11. 1979. .
ADDRESSES: A Background Information
Document (BID; EPA 450/3-79-(21) hat
been prepared for the fmal 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 i.
available for inspection in the Office of
Public Affairs in each Regional Office.
and in EPA'. Central Docket Section in
\\' ashmgton. 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.. particulate
malt.'.. and NO. emissions: and (3) the
fmal !1vironmentallmpact Statement
whicJ ;ummarizes the impact. of the
regula Ion.
Docket No. OAQPS-78-1 containing
all supporting information u.ed by EPA
m developing the standards is available
for public inspection and copymg
between 8 a.m. and 4 p.m.. ge
alllnO.OO5Monday 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 con.idered by
the Administrator in the development of
this rulemaking. The docketing .ystem is
intended to allow member. of the public
and indu.tries involved to readily
identify and locate document. .0 that
they can intelligently and effectively
participate in the rulemaking process.
Along with the statement of baais 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
(.ection 107(d)(a}).
FOR FURTHER 'NFORMAnON 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.
8UPt'LEMENTARY INFORMAnON: This
preamble contain. a detailed di,cullion
of this rulemaking under the following
headings: SUMMARY OF STANDARDS.
RATIONALE. BACKGROUND.
APPUCABIIJTY. COMMENTS ON
PROPOSAL. REGULATORY
ANALYSIS. PERFORMANCE TESTING.
MISCElLANEOUS.
S~ofStaDd~
Applicability
The standards apply to electric utility
.team generating unit. cap~ble of firing
more than 73 MW (250 million Btu/hour)
heat input of fOllil fuel. for which
construction i. commenced after
September 18. 1978. Industrial
cogeneration facilitie. that .ellle.. than
25 MW of electricity. or le.s than one-
third of their potential electrical output
capacity. are not covered. For electric
utility combined cycle gas turbines.
applicability of the .tandard. i.
determined on the baais of the fo.sil-fuel
fired to the steam genera tor 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 .olid .olvent refined coal): So.
emi..ion. 10 the atmosphere are limited
to 520 ng/J (1.20 Ib/millinn Btu) heat
input. and a 90 percent reduction in
potentia] SO. emissions is required at all
times except when emissions to the
atmosphere are less than 260 ng/J (0.60
Iblmillion Btu) heat input. When SO.
emissions are less than 260 mg/} (0.60
Iblmillion Btu) heat input. a 70 percent
reduction in potential emissions is
102
required. Compliance with the emilSion
limit and percent reduction rll'tjuirements
is determined on a continuous basis by
using continuous monitors to obtain a
3O-day rolling average. The percent
reduction i. computed on the basis of
overall SO. removed by all types of SO.
and sulfur removal technology. includinll
flue gas desulfurization (FGD) systems
and fuel pretreatment systems (.uch 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
inlo the atmosphere are limited to 340
ng/} (0.80 Ib/miUion Btu) heat input. and
a 110 percent reduction in potential SO.
emissions is required. The percent
reduction requirement does not apply if
SO. emissions into the atmo.phere are
less than 86 ng/J (0.20 Ib/million Blu)
heat input. Compliance with the SO.
emi.sion limitation and percent
reduction is determined on a continuous
basis by using continuous monitors to
obtain a 3G-day rolling averaga.
(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/} (1.20 Iblmillion Btu) heat input
emilSion limit on 8 3G-day rolling
average. and all other provisions of the
regulation. including the particulate
matter and NO. .tandard..
(4) Noncontinental areas: Electric
utility. steam generating unit. located in
non continental areas (State of Hawaii.
the Virgin Island.. Guam. American
Samoa. the Commonwealth of Puerto
Rico. and the Northern Mariana I~ands)
are exempt from the percentage
reduction requirement of the SO.
standard but are 'Subject to the
applicable SO. emission limitation and
all other provi.ions of the regulation.
including the particulate matter and NO.
standards.
(5) Resource recovery facilities:
Resource recovery facilities that fire lel8
than 25 percent fossil-fuel on a quarterly
(90-day) beat input basis are not subject
to the percentage reduction
requirements but are .ubjei:t to the 520
"l/J (1.20 Iblmillion Btu) heat input
emission limit. Compliance with the
emission limit i. determined on a
continuous basis using continuous
monitoring to obtain a 3O-day rolling
average. In addition. .uch facilities must
monitor and report their heat input by
fuel type.
(6) Solid solvent refined coal: Electric
utility stea~ generating units firing solid
solvent refmed coal (SRC I) are subject
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Federal Register I Vol. 44. No. 113 / Monday. June 11. 1979 I Rules and Regulations
33531
to the 520 ngfl (1.20 Ibfmillion Btu) heat
input emission limit (3D-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
a continuous monitor to obtain a OO-day
rolling average. The percentage
reduction requirement for SRC I. which
is to be obtained at the refining facility
itself. is 85 percent reduction in potential
SO. 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.
Particulate Matter Standards
The particulate matter standard limits
emissions to 13 ngll (0.03 lbfmillion 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 ngfl (0.20 Ib/million Btu) heat
input from the combustion of any
gaseous fuel. except gaseous fuel
derived from coal:
[2) 130 ngll (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 ngll (0.50 Ibfmillion Btu) heat
input from the combustion of
subbituminous coal. shale oil. or any
solid. liquid. or gaseous fuel derived
from coal;
(4) 340 ngll (0.80 Ibfmillion 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 trom the NO, standards
and monitoring requirements; and
(6) 260 ngll [0.60 lb/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 3D-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 Technalogies
The standards include provisions
which allow the Aclministrator 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
ngfl [1.20 lb/million Btu) heat input.
based on a Jo-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 ngll heat input limit
(OO-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 SO. standard and to
the particulate matter and NO,
standards. However. the reduction In
potential SO. emissions allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants usinll FBC would be 85 percent
(based on a 3D-day rollinll averalle). The
NO, emission limitation allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants usinll coal liquefaction would be
300 ngll (0.70 lbfmillion Dtu) heat input.
based on a OO-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:
Tec/InoIogy
EQUIVaJent
PaMMI 8I8c1ncoI-
MW
Sobd 5OMtnt.fefined coal . ......
FMdrz8d bed combu8tton
(81mosp/W1c)
Auodozod bed comt>ua1lOn
(pr."""'8d1
Cool 'oquot8C1lOn ............ ..........
so,
so,
5.000-10.000
.00-3.000
so.
NO.
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
103
approved p!'ocedures must be used to
supplement the emission data when the
continuous emission monitors
malfunction. to provide emissions dala
for at least 18 hours of each day for a I
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 Ihe
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 111(a) of the Act. a
standard of performance for a fosst!-
fuel-fired stationary source must reflect
the desree 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 enel'llY 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.
In the 1977 amendments to the Clean
Air Act. Conllres8 was severely critical
of the current standard of performance
for power plants. and especially of !he
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 lonll-term economic growth
by reducinll 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 installa tion 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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Federal Register I Vol. 44, No. 113 I Monday. June 11. 1979 I Rules and Regulation.
is 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 standaro.
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 emillions, compared to
the emissions that would result from
burning untreated fuels.
Tl:e Conference Committee generally
followed the House bill. As a result. the
1977 amendments substantially chall8ed
the criteria for regulating new power
plants by requiring the application of
technological methods of control to
mi~imize SO. 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 fOil ii-
fuel.fired stationary sources to specify
(1) an emission limitation and (2) a
percentage reductian 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
cho: Jcteristics 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
thos,' burning higher sulfur coal. The
pub' comments on the proposed rules
d'fid bsequent analyses performed by
the C, ;ce of Air. Noise and Radiation of
EPA suved to bring into focus several
u:~.er Issues as well.
These ISSLes i::c!uded performance
capJbillties of SO. control technology.
the averaging period for determining
compilance. and the potential adverse
impdct of the emission ceiling on high-
su;Cur coal reserves.
Prior to framill8 the final SO.
standards, the EPA stall carried out
extensive analyses of a range of
alternative SO. standard. 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 othen reviewed the underlying
a..umption. used in the model The
results of theae analy.es 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
emission ceilings on specific coal
reserves, to verify performance
characteristics of alternative SO.
scrubbing technologies, and to assess
the sulfur reduction potential of coal
preparation techniques.
Baeed 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. Thi.level can be achieved
at the individual plant level even under
the most demanding conditions through
the applica tion 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 roIling average as the basis for'
determining compliance. the
Administrator took into consideration
effects of coal sulfur variability on
scrubber performance as well as
potential ad\'erse 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
104
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 establishilll a national percent reduction
fDr new fDIlU fuel-fired SDurces. the
cDnferees agreed that the AdministratDr msy.
in hil discretion. set a r8111e Df pDllutant
reductiDn that renects varyina fuel
characteristics. Any departure frDm the
unifDrm natiDnai percentage reductiDn
requirement. however, must be accDmpanied
by a findilll that such a departure dDes nDt
undermine the balic PUrpDSes of the HDuse
prDvisiDn and Dther prDviliDns Df the act,
luch al maximizing the use Df IDcally
available fuell.
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
analysi. 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 reault 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
1961-1962 period. These already
contracted systems have design
efficiencies ranging from 50 to 65
percent SO. removal, long term average.
In addition. iLwas 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 designs offer 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 nglJ (3 pounds
SO./million Btu), or aboull.5 percent
sulfur coal. available data indicate that
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Federal Register I Vo\. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
31583
it probably will be more economical to
employ a wet scrubber than a dry
control system.
Faced with these fmdings. the
Administrator had to determine what
effect the structure of the final
regulation would have on the continuinz
development and application of this
technology. A thorough engineering
review of the available data indicated
that a requirement of 90 percent
reduction in potential SO. 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 SO.
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 (3D-
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 interm~diate
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 thesll 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 emiuion
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 lb/minion Btu) heat
input on a 3D-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 t1m coal markets in
these regions. Accordingly. the
Administrator concluded the emission
limitation should be maintained at 520
ng/) (1.2 lb/million Btu) heat input on a
3D-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/) (1.2 lb/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 ngl
J (0.6 lb/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.
105
provided their emissions were less t h, J n
260 ng/J (0.61b/million Btu). The 250 r,~1
J (0.6 lb/million Btu) level was selectel!
to provide for a smooth transition of the
percentage reduction requirement i:-om
high- to low-sulfur coals. Other
..ansition points were examined but nut
adopted since they tended to pldcc
certain types of coal at a dis8dvanIB~e.
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 anyone coal
producing region. The maintenance of
the emission limitation at 520 ng/! [1.2 Ib
SO./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 ~o
percent on low-sulfur coals. the final
rule encourages the full developmen t
and application of dry SO, control
systems on a range of coals. At the same
time. the minimum requIrement 15
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 hiQh-
sulfur coal production. By achievIng]
balanced coal demand wllhIn the u:,j:lv
sector and by promoting the .
development of less expensive SO,
control technology. the final standdrd
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Federal Register I Vol. 44, No. 113 I Monday, June 11, 1979 I Rules and Regulations
will expand environmentally acceptable
energy supplies to existing power plants
and Industrial sources.
By substantially reducing SO.
emissions. the standard will enhance the
potential for long tenn economic growth
at both the national and regional levels.
While more restrictive requirements
may have resulted in marginal air.
quality improvements locally, thetr
higher costs may well have served to
retard rather than promote air quality
improvement nationally by delaying the
retirement of older, poorly controlled
plants.
The standard must also be viewed
within the broad context of the Clean
Air Act Amendments of 1977. It serves
as 8 minimum requirement for both
prevention of significant deterioration
and non-attainment consideration..
When warranted by local condition.,
ample authority exists to impo.e more
restrictive requirements through the
case-by-case new source review
process. When exercised in conjunction
with the standard. these authoritie. will
assure that our pristine areas and
national parks are adequately protected.
Similarly, in tho.e areas where the
attainment and maintenance of the
ambient air quality standard i.
threatened, more restrictive
requirements will be impo.ed.
The standard limits SO. emissions
from facilities firing gaseous or liquid
fuels to 340 ngll (0.80 Ib/million Btul
heat input and requires 90 percent
reduction in potential emissions on a 30-
day rolling average basis. The percent
reduction does not apply when
emissions are less than 86 ngll (0.20 lb/
million Btu) heat input on a 3D-day
rolling average basIs. This reflects a
chanl!e to the proposed standards in
th..t the time for compliance is changed
from the proposed 24-hour basis to a 30-
(by rolling a I'erage. This chapge is
necessary to make the compliance times
consistent for all fuels. Enforceml'r.! of
thl' standards would be cumpitcated by
different averagmg timl's. partIcularly
",hen more than one fuel is used.
P-::'."'o'culate "Jalter Standard
T , standard for parhcula!e matter
!in. the emissIOns to 13 ng/I [0.03 lil/
nil I. 1 OIu) heat input and requires a 99
pe"ce ,t reduct.on in uncontrolled
I'nuss,ons for solid fueis and a 70
pl'rrent reduction for liquId fuels, No
part;culate matter control IS nl'cessary
for umts finn!! gasl'ous fuels alone. and
a percent reduction IS not required. The
::;I'rcl'nt rl'ductlon rl'qulfements for solid
and liquid fuels are not controlling, and
r.or:1pl:ance with the particulate matter
emiuion limit will assure compHance
with the percent reduction requirements.
A 20 percent (8-minute average)
opacity limit is 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 .tandards
except opacity. the owner or operator
may request that the Administrator.
under 40 CFR 6O.11(e). establish a
source-specific opacity limit for that
affected facility.
The standard is based on the
perfonnance of a well designed.
operated and maintained electrostatic
precipitator (ESP) or baghouse control
system. The Administrator has
determined that these control system.
are the best adequately demonstrated
technological .ystems of continuous
emillion reduction (taking into
consideration the cost of achieving such
emilSion reduction. and nonair quality
health and environmental impacts and
enel'8Y requirement.).
Electrostatic Precipitators
EPA collected emission data from 21
ESP-equipped steam generating units
which were firing low-sulfur coals (0.4-
1.9 percent). EPA evaluated emiasion
levels from units burning relatively low-
sulfur coal because it is more difficult
for an ESP to collect particulate matter
emissions generated by the combustion
of low-.ulfur coal than high-sulfur coal.
None of the ESP control systems at the
21 coal-fired steam generatora tested
were designed to achieve a 13 ngIJ (0.03
lb/million Btu) heat input emi88icn level,
however, emission levels at 9 of the 21
units were below the standard. All of
tbe units that were firing coal with a
sulfur content between 1.0 and 1.9
p~rcent and which had emilSion levels
below the standard had either a hot.side
ESP (an ESP located before the
combustion air preheater) with a
specific colIection area greater than 89
square meters per actual cubic meter per
sl'cond [452 f:'/1.000 ACFM), or a cold-
sIde ESP (an ESP located after the
combustion air preheater) with a
specific collection area greater than 85
square ml'ters pl'r actual cubic meter pl'r
s('cond [435 ft'/1.000 ACFM).
ESP's require a larger ~pecific
collection area when applied to units
burning low-sulfur coal than to umts
burning high-sulfur coal because the
electrical resistivity of the fiy ash is
higher with 10w-suJiur coal. Based on an
examination of the emission data in the
record, it is the Admihistrator's
judgment that when low-sulfur coal is
bemg fired an ESP must have a specific
106
collection area from about 1310 (hot side)
to 200 (cold side) square meters per
actual cubic meter per second (650 to
1,000 ft' per 1,000 ACFM) to comply with
the standard. When high-sulfur coal
(greater than 3.5 percent sulfur) is being
fired an ESP must have a .peciEic
collection area of about 72 (cold side)
square meters per actual cubic meter per
second (360 ftl per 1,000 ACFM) to
comply with the standard.
Cold-side ESP's have traditionally
been used to control particulate matter
emissions from power plant.. The
problem of ESP collec'tion of high-
electrical-re.istivity fly ash from low-
sulfur coal can be reduced by using a
hot-side ESP. Higher fly ash collection
temperatures result in better ESP
performance by reducing fly ash
resistivity for most types of low-sulfur
coal. Reducing fly a.h resistivity in itself
would decrease the ESP collection plate
area needed to meet the standard;
however. for a hot-side ESP this benefit
is reduced by the increased flue gas
volume resulting from the higher flue gas
temperature. Although a smaller
collection area i. required for a hot-side
ESP than for a cold side ESP, this benefit
is off.et by greater construotion costs
due to the higher quality of materials,
thicker in.ulation, and special design
provisions to accommodate the
expansion and warping potential of the
collection plates.
BaghouselJ
The Administrator has evaluated data
from more than 50 emission test runs
conducted at 8 baghouse-equipped coal-
fired steam generating unit.. Although
none of these baghouse-controlled units
were designed to achie':B a 13 Ng/J (0.03
lb/million Btul heat in~1 emission level.
48 of the test results achieved this level
and only 1 test at each of 2 units
exceeded 13 NglI (0.03 lb/mllhon Btu)
heat input. The emission levels at the
two units with emission levels above 13
NglI (0.03 !e/million Btu) heat input
could conceivably be reduced below
that level through an improved
maintenance program. It is the
Administrator's jadgment that
baghouses with an alr-to-cloth ratio of
0,6 acll'iil cubic meter per min'lte per
square meter (2 ACFM/ft") will achieve
the standard at a pressure drop of less
thdn 1.25 kIlopascals [5 in. H.O). The
AdIT'olnistrator has concluded that this
air/cloth ratio and pressure drop are
reasonable when considering cost,
energy, and nonair quality impacts.
\Vhen an owner or operator must
choose between an ESP and a baghouse
to meet the standard, it is the
Administrator's judgment that
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33585
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-con trolled 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 iulfur. The baghouse control
system for this facility is designed to
achieve a 43 Ng/J (O.Ollb/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/ft") and a pressure drop of
1.25 kilo pascals (5 in. H.O). 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 conaol
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 NglJ (0.05 Ib/million
Btu) heat input. Only one of the seven
units had emission test results less than
13 NglJ (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
considerations. the 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 FGD 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, and
operated FGD system. No additional
Information has been received to alter
this fmding.
The data available at proposal
Indicated that sulfuric acid mist (H.SO.)
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 tes ting 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
107
(0.03 Ib/million I3tu) heat input. The '''':5
at both facilities were conducted us,n~
Method 5. but different methods were
used for measunng the filter
temperature. EPA has initiated a reView
of Methods 5 and 17 to determine \\ rod!
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 TESTL'JG section of
this preamble.
The particulate matter emission I:mlt
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 utilitv
iRdustries (see discussion under'
REGULATORY ANALYSIS). This
projection took into consideration the
combined effect of complying with the
revised SO.. particulate matter. and :";0.
standards on the construction and
operation of both new and existing
capacity. Particulate matter emissions
from power plants were 3.0 million Ions
in 1975. Under continuation of the
current standards, these emisiions 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 predlct~d
to decrease another 400 thousand tons
(30 percent).
NO. Standards
The NO. emission standards are
based on emission levels achie'l8ble
with a properly designed and opera teJ
bOiler that incorporates combu~tion
modification techniques to reduce :V).
formation. The levels to which :'-;0,
emissions can be reduced with
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Federal Register I Vol. 44. No. 113 I Monday, June 11, 1979 I Rules and Regulations
combustion modification depend not
onh' upon boiler operating practice. but
alntnuous compliance with the NO,
standards is required. based on a 3G-day
rollt:1s;! average. Also. perr.ent reductions
It. uncontrolled NO, emission levels are
requ "ed. The percent reductions are not
controlling. however. and compliance
with the NO. emIssion limits will assure
compliance with the percent reduction
reoUlrements.
One chanlle has been made to the
proposed NO, st.1ndards. rhe proposed
standards would have required
cOr.1pliance to be based on a 24-hour
8 \" eralling period. whereas the final
standards require compliance to be
based en a 3G-day rollil1g average. This
ch~n,;:e was made because several of the
comments received. one of which
included emission data. i'1dicated that
more nexibility in boiler operation on a
da\.-to-day basis is needed to
accommodate slallglng and other boiler
problems that may innuence NO,
emissions when coal is burned. The
a\'eralling period for determining
comp'iance with the NO,limitations for
ga seaus and liquid fuels has been
changed from the proposed 24-hour to a
30-cay rolling average. This change is
necessary to make the complial1ce times
consistent for all fuels. Enforcement of
the s~andards 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 resuits of EPA testing performed at
si", electric utility boilers. all of which
a re considered to represent modern
bl'li~r designs. One of the boilers was
m""ufactured by the Babcock and
Wllec", Company (Bt.W) dnd was
retr ,f,lIed with 10w-emi5sion burners.
Fo~r of the bOIlers were Combustion
Enb'-eeri"!!, Inc. (CE) designs oriRinal!y
equ', ~ed with overfire air. and one
bc.!. \las a CE design retrofitted with
0\ er: . 3 ir The six boilers burned a
\,,j -"'\ of btu;,"!inous and
0,; '~'.i_:ninous coals. Conclusions
,:ra\\":l :'am the EPA studies of the
Lc.'us were that the most effec~ive
cOc,busllen mod;[icatlOn techniques for
reducmg !\:O, emitted from utility
bOl:~rs arc staged combustIOn. low
exees; air, dnd reduced heat release
rate Low-emIssion burners were also
effective in reducing NO, level8 durins
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 CEo 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 BllrW. 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 81
those proposed; and (6) g".larantees
made by B&:W and FW that their new
boilers would achieve the State of New
Mexico's NO, emission limit of 190 ng/f
(0.45 Ib/million Dtu) heat input.
Since proposal of the standards. the
following new information has become
available and h81 been considered by
the Administrator: (1) additional data
from the boiler manufacturers on four
BllrW and four RS utility boilers; (2) a
total of 16 months of contiDl!ously
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
4SO/3-7~21).
The data available before and after
proposal indicate that NO, emission
levels below 210 nglJ (0.50 lb/million
Btu) heat input are achievable with a
variety of coals burned in bOilers made
by all fnur of the major boiler
manufacturers. Lower emission le\'els
are theoretically achieva ble 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,
108
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
t"e other boiler manufacturers. the
Administrator believes that the emission
variability exhibited by CE boilers over
long periods of time is also
characteristic ofB&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 3G-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. Tbe
severity of tube wastage is believed to
vary wi th 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 reducins 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 hi;jh 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 evalualion of
all available tube wastage information.
the Administrator bas established an
NO, emission limit of 260 nglJ (0.60 Ib/
million Btu) heat imput for the
combustion of bituminous coal. The
Administrator believes this is a safe
le\'el at which tube wastage will not be
accelerated by low-NO, operation. In
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Rtgulations
33587
support of this belief. CE has stated that
it would guarantee its new boilers. when
equipped with overfire air. to achieve
the 260 nglJ (0.60 Ib/million Btu) heat
input limit without increased tube
wastage rates when Eastern bituminous
coals are burned. In addition. B&W has
noted in several recent technical papers
that its low-emission burners allow the
furnace to be maintained in an oxidizing
atmosphere. thereby reducing the
potential for tube wastage when high-
sulfur bituminous coals are burned. The
other boiler manufacturers have also
developed techniques that reduce the
potential for tube wastage during low-
NO, operation. Although the amount of
tube wastage data available to the
Administrator on 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 a result of compliance with the NO,
standards.
Since the potential for increased tube
wastage during low-NO, operation
appears to be small when low-sulfur
subbituminous coals are burned. the
Administrator has established a lower
NO, emission limit of 210 ng/' (0.50 lb/
million Btu) heat input for boilers
burning subbituminous 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 NO, limit
of 210 ngf' (0.50 Ibfmillion Btu) heat
input. without increased tube wastage
rates. when sub bituminous coals are
burned.
The emission limits for electric utility
power plants that bum 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 NO, 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 known emission characteristics of
coal. the Administrator believes that an
achievable emission limit for solid.
liquid. and gaseous fuels derived from
coal is 210 ngf' (0.50 lb/million Btu) heat
input. Tube wastage and other boiler
problems are not expected to occur from
boiler operation at levels as low as 210
nglJ when firing these fuels because of
their low sulfur and ash contents.
NO, emission limits for lignite
combustion were promulgated in 1978
(48 FR 9276) as amendments to the
original standards under 40 CFR Part 60.
Subpart D. Since no new information on
NO, emission rates from lignite
combustion has become available. the
emission limits have not been changed
for these standards. Also. these
emission limits are the same 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 NO, emissions from
shale oil combustio~. Consequently. the
Administrator has limited NO,
emissions from units burning shale oil to
210 ngf' (0.50 lb/million Btu) heat input.
the same limit applicable to
sub bituminous coal. which is the same
as proposed. There is no evidence that
tube wastage or other boiler problems
would result from opera tion of a boiler
at 210 ngf' 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 NO,
standard. Unlike lignite. '.'irtually 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 NO, standards were estimated
by using an economic model of the coal
and electric utility industries (see
discussion under REGULATORY
ANALYSIS). This projection took into
109
consideration the combined effect of
complying with the revised SO..
particulate matter. and :-.10, standards
on the construction and operation of
both new and existing capacity.
National NO, emissions from power
plants were 6.6 million tons in 1975 and
are predicted to increase to 9.3 m1l1101I
tons by 1995 under the curren t
standards. These standards are
projected to reduce 1995 emissions by
600 thousand tons (6 percent).
Background
In December 1971. under section 111
of the Clean Air Act. the Administrator
issued standards of performance to I1mlt
emissions of SO.. particulate matter.
and NO, from new. modified. and
reconstructed fossil-fuel-fired steam
generators (40 CFR 60.40 et seq.). Since
that time. the technology for controlling
emissions from this source category has
improved. but emissions of SO..
particulate matter. and NO. continue to
be a national problem. In 1976. steam
electric generating units contributed 24
percent of the particulate matter. 65
percent of the SO.. 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 fossil-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 ~oo
million tons/year in 1975 to about 1250
million tons/year in 1995. Under the
current performance standards for
power plants. national SO. emissions
are projected to increase approxima tely
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 SO. emissions are expected 10
increase 1300 percent by 1995 in the
West South Central region of the
country (Texas. Oklahoma. Arkansas.
and Louisiana).
EPA was petitioned on August 6. 19~6.
by the Sierra Club and the Oljato Ji'd
Red Mesa Chapters of the Navaho Tnbe
to revise the SO. standard so as to
require a 90 percent reduction in SO.
emissions from all new coal-fired po'.ver
plants. The petition claimed that
advances in technology since 1971
justified a revision of the standard. As a
result of the petition. EPA agreed 10
investigate the matter thoroughly. On
'anuary 27. 1977 (42 FR 5121). EPA
announced that it had initiated a study
to review the technological. economIc.
and other factors needed to determJr.e 10
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
-
what extent the SO, standard for fossil-
f.."l.rired steam generators should be
revised.
Oil August 7, 1977. President Carter
signed into law the Clean Air Act
Amendments of 1977. The provisions
under section 111(b)10) of the Act. as
amended. required EPA to revise the
s:andards of performance for fossil-fuel-
fired electric utility steam generators
wIthin 1 year after enactment
After the Sierra Club petition of
August 1970, EPA initiated studies to
review the advancement made on
po:!ution control .y.tem. at power
plants. The.e studie. 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 WBI
made in lale 1977. A National Air .
Pollution Control Technique. Advisory
Commillee meeting was held on
December 13 and 14. 1977, to present
EPA preliminary data. The meeting wa.
open to the public and comment. were
solicIted.
The Clean Air Act Amendments of
1977 required the standard. to be
revised by Augu.t 7. 1978. When it
appeared that the Admini.trator would
not meet this schedule. the Sierra Club
filed a complaint on July 14, 1978. with
the llS. Dis trict Court for the District of
Columbia requestiD8 injunctive relief to
require, among other things. that the
Administrator propose the revised
standards by AugUlI 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
rropcsal package to the Office of the
F"deml Register by September 12. 1978.
and the ;>roposed regulatIons were
puolished September 19. 1978 (43 FR
4::1:;4). PuLlic comments on the proposal
weep requested by December 15, and a
rLblic hearing was held December 12
And 13. the record of which was held
cpe" lOtil January 15, 19:'9. More thaD
6~5 e TIment let~crs were received on
t},e r ;Josal. The comments were
r J CI" Y considered, hoy, ever, the
iSS'JCS ould not be sufficlentJy
e\":catcd in time to promulgate the
stanG.Jrds by March 19, 1979. On that
datp. the Administrator and the other
panics in Sierra Club v. Costle f,Ied
with the Court a stipulation whereby the
Adm::1istrator would sign and deliver
the final standards to the federal
Register on or beforc June 1. 1979.
The Administrator's conclusions and
responses to the major issues are
presented in this preamble. These
regulations represent the
Admini.trator's response to the petition
of the Navaho Tribe and Sierra Club and
fulfill the rulemaking requirements
under section 111[b)(6J of the Act,
Applicability
General
The.e standards apply to electric
utility steam generating units capable of
firing more than 73 MW (250 million
Btu/hour) heat input of fossi! 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 fo.si!-fuel-fired
steam genera tOri used in electric utility
and large industrial applications. The
standards adopted herein do not apply
to electric utility steam generating unit.
originally subject to those .tandards
(Subpart D) unless the affected faciliUe.
are modified or reconstructed as defined
under 40 CFR 60 Subpart A and this
subpart. Similarly, units constructed
prior to December ::3. 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 i. physically
connect~" to a utility power distribution
system and is constructed for the
purpo.e 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
el~ctrical genera ting 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 eleClrical
out;>ut capacity has also been added
since proposal.
These standards cover industrial
steam electric generating units or
cogeneration units (producing steam for
both electrical genera tion and process
heat) that are capable of firing more
than 7J MW (250 million Btu/hr) heat
110
input of fossil fuel and are constructed
for the purpose of selling through a
utility power distribution system mor'!
than 25 MW electrical output and more
than one-third of the:r potential
electrical out;)Ut 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 indUltrial steam or that generate
electricity but sellle8s 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 Subpm D.
if applicable.
Resource recovery units incorporating
steam electric geITerating unit. that
would meet the applicability
requirement. but that combust less U,an
25 percent fOSli! fuel on a quarterly (90-
day) heat-input basis are not covered by
the SO. percent reduction requirements
under thi. standard. These facilities are
subject to the SO. emission limitation
and all other provi.ion. of the
regulation. They He also required to
monitor their heat input by fuel type and
to monitor SO. emissions. U more than
25 percent fo.si! fuel is fired on a
quarterly heat input ba.is. 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 gal 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 9team
genE:rators that are not capable of being
fired with more than 73 MW (250 million
Btu/hr) of fossi! fuel are not covered by
the standards.
Madlfication/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 thi. 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 nonIossil fuels or 10
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Federal Register I Vol. 44. No. 113 I Monday, June 11. 1979 I Rules and Regulations
33589
~xisting facilities that were designed to
(ire gas or oil fuels and that are modified
:0 fh'e shale oil. coal/oil mixtures. coal/
Dil/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.
Comments on 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 18. 1978. are covered. Since
proposal, changes have been made to
specific applicability requirements for
industrial cogeneration facilities.
resource recovery facili ties. and
anthracite coal-fired facilfties. 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 and
plans to propose them in 1980.
Cogeneration Facilities
Cogeneration facilities are covered
under these standards if they have the
capabilitv 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 rel1ects 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
expt!cted to be 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-electrtc generating set may be
matched with a much larger industrial
steam generator (larger than 250 million
Btu/hr for example). The Administrator
intended that 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
cogeneration 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 dermed 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
111
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 [inc1ud;nf!
electrical generation technologies with
inherently low emissions or high
electrical genera tion efficiencies) the
owner or operator may apply to the
Administrator under section 111[j) of the
Act for an inn~vative technology waiver
which will allow for (1) up 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 grea tel'
continuous emission reduction or
achieve equivalent reductions at low
cost in 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. under which 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 recoverv
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 \\11th d
low-sulfur content that can be stored
and subsequently fired. The commenter
suggested that when firing processed
refuse fuel. little if any fossil fuel W11l be
necessary for combustIOn stabIliza !or,n
over the long term: however. fossIl fud
will be necessary for startup. \Vhen a
cold unit is started. 100 percent foss,1
fuel (oil or gas) may be fired for a It \V
hours prior to firing 100 percent
processed refuse.
Other commenters suggest,!d that
resource recovery facilitIes would In
many cases be owned and operateu by a
municipality and the electricity and
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Federal Re~isler / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Re~uIalion8
,:,'co:'. ~enerated would be sold by
,'r, 'c~c: to of:.et operati~& costs. U:lder
: .,< '1 dn a;rangement. commenten
:lJ,,,e~:"c that there'may be a need to
he lass,; fuei on a short-term basis
when re;use is nut readily available in
order to g"nerate a reliable supply of
S't'd rr. for !he contract customer.
The Administrator accepts these
su~~~stions and doe. not wish to
d,~coura~e the construction of resou~ce
ri:!:overy fa~Hiiles that senerale
eJec'riclty and/or indus!rial steam. For
I ese,urce recovery facilities. the
Adr:-.lnistrat'Jr believes that less thlln 25
pt'fc"nt heat input fro::! fossil fuels will
be req"lred on a long-term basI.: even
though 100 percent fossil fuel firing
l!e rr.!'1es wIll result In
:m,',; ,J\'eme:!! of acid.mine,water
COt1'~I;IOns, pllmlnatlon of old mimng
~,
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
33591
power demand or complying with the
slandards. These emergency provisions
are discussed in a subsequent section of
this preambie.
Concern was expressed by the
commenters that the cost impact of L'1e
standard would be excessive and that
the benefits do not jus.tify 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
malerials 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 concludeq
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.
NoncontinentaJ 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 SO. 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 (3D-day rolling
average) for coal and 340 nglJ (0.8Ib/
million Btu) heat input (3D-day rolling
average) for oil. in addition to all
requirements under the NO, and
. particula Ie ma Her standards. This is the
same as the proposed standards.
Although this provision was identified
as .In 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 nOl 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 regula lions.
In general. the comments received on
the proposed regula tions were
supportive. although a few commenters
suggested some changes. A few
commenters indicated that section 111(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 coalliquefaclion
ca tegory for purposes of alloca ting the
15.000 MW equivalent electrical
capacity.
On the basis of the comments and
p'lblic 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 111(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 do not 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
113
been retained for SRC-I because it has
relatively uniform emission rates. \\ hlcn
makes a 24-hour averaging period more
appropriate than a 3D-day rolling
average.
Commercial demonstration permIts
establish les8 stringent requirements for
the SO. 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 lhat
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
theAc!.
ModificationlRecons truction
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 6O.4Oa. 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 electnc utility
steam generating units will become
subject to these standards.
The preamble to the proposed
regulations did not provide a detailed
discussion {If the modifica tion/
reconstruction provisions. and the
comments received indicated that these
provisions were not well understood by
the commenters. The general
modiIication/reconstruction provisions
under 40 CFR 60.14 and 60.15 apply to 311
source categories covered under Part 60.
Any source-specific modification/
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33592
Federal Register I Vol. 44, No. 113 I Monday, June 11. 1979 I Rules and Regulations
reconstruction provisions are defmed in
more detail under the applicable subpart
(60.4Oa for this standard).
A number of commenters expressly
requested that fuel switching provisions
be more clearly addressed by the
standard. In response, the Administrator
hu clarified the fuel switching
provisions by including them in the fmal
standards. Under these provisions
existing facilities that are converted to
noruoslil fuels are not considered to
have undergone modification. Similarly.
exilting facilities designed to fire gas or
oil and that are converted to shale oil,
coal/oil mixtures, coal/oil/water
mixtures. solvent refined coal. \iquified
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 wu mentioned in the
Federal Regiater preamble for the
proposal.
SO. Standard.
SO. Control Technology-The final
SO. Itandarda are b8led on the
performance of a properly designed.
installed. operated and maintained FGD
system. Although the standards are .
bued on lime and limeltone FGD
systems, other commercially available
FGD systems (e.8., Wellman-Lord.
double alkali and msgnesium oxide) are
also capable of achieving the final'
standard. In addition. when specifying
the form of the final Itandards. the
Administrator considered the potential
of dry SO. control system. as disculled
later in thil section.
Since the standards were proposed.
EPA'hal continued to collect SO. data
with continuous monitors at two sites
and initiated data 8athering at two
additional site.. At the Conesville No.5
plant of Columbus and Southern Ohio
Electric company. EPA gathered
continuous SO. data from July to
December 1978. The Conesville No.5
FGD unit is a turbulent contact ablorber
(TCA) scrubber using thiosorbic lime al
the Icrubbing medium. Two parallel
modules handle the g88 flow from a 411-
MW boiler firing run-of-mine 4.5 percent
sulfur Ohio coal. During the test period.
da ta f CJr only thirty-four 24-hour
aver ing period. were gathered
beca. ~ of frequent boiler and Icrubber
outage. The Conesville system
averaged 88.8 percent SO. removal. and
outlet SO. emissions averaged 0.60 Ib/
million Btu. Monitoring of the Wellman-
Lord FGD unit at Northern Indiana
Public Service Company's Mitchell
station during 1978 included one 41-day
contmuous period of operation. Data
from this penod were combined with
- -
~No.S.._--_..._...- _~CA._.__-
NIPSCO .-------- W-.u.nI.--
-..---.--- lJm8ITCA...___..__._-
'---No.. ---.-.-.-....,.- ~-_._--
previoUi data and analyzed. Results
indicated 0.611b SOo/million Diu and
89.2 percent SO. rell)oval for fifty-six 24-
hour periods.
From December 1978 to February 1979,
EPA gathered SO. data with continuous
moniton at the 1D-MW prototype unit
(using a TCA absorber with lime) at
Tennessee Valley Authority's (TVA)
Shawnee Itation 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 W88 f11'8d. Sulfur
I dioxide removal averaged 88.6 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 SO.
removal W81 96.6 percent. The Shawnee
and Lawrence tests also demonstrated
that SO. monitors can function with
reliabilities above 60 percent. A
summary of the recent EPA-acquired
SO. monitored data fonows:
tGoI-.
pet.
U
3.5
3.0
0.5
No. 01 2..
hoU' ....-
~
51
.z
22
"- so,
-".pel
SU
11.2
11.1
88.S
Since proposing the standards, EPA
h81 prepared a report that updates
Information in the earlier PEDCo report
on FGD systems. The report includes
listings of several new closed-loop
systems.
A variety of comments were received
concerning SO. control technology.
Several comments were concerned with
the use of data &om FGD systems
operating in Japan. These co~nts
suuested that the Japanese experience
shows that technology exists to obtain
greater than 90 percent SOt removal.
The commenten pointed out that
attitudes of the plant opera ton. the skin
of the FGD system operalo\'8. the close
surveillance of power plant emissions by
the Japanese Government. and technical
differences in the mode of scrubber
operation were primary facton in the
higher FGD reliabilities and efficiencies
for Japanese sYltems. These commenters
stated that the Japanese experience i.
directly applicable to U.S. facilities.
Other comment. .tated that the
Japanese sYltems cannot be used to
support Itandard. for power plant. in
the U.S. because of the possible
differences in facton such as the degree
of closed-loop versus open-loop
operation. the impact of trace
constituents such 81 chlorides, the
differences in inlet So. concentrations,
So. uptake per volume of slurry,
Japanese production of gyplum instead
of sludge. coal blending and the amount
of maintenance.
The comments on cloled-Ioop
operation of Japanese systems inferred
that larger quantities of water are
purged from these sYltems than from
their U.S. counterparts. A clo.ed-Ioop
114
.y.tem is one where the only water
leaving the system is by: (1) evaporative
water lo.ses in the scrubber. and (2) the
water associated with the sludge. The
administrator found by investigating the
.ystems referred to in the comments that
six of ten Japane.e .ystems li.ted by
one commenter and two of four coal-
fired Japane.e .ystem. are operated
within the above definition of closed-
loop. The closed-loop operation of
Japane.e scrubbers was al80 attested to
in an Interqencey Task Force Report,
"Sulfur Oxides Control Technology in
Japan" Uune 30. 1978) prepared for
Honorable Henry M. Jackson. Chairman,
Senate Committee on Energy and
Natural Resources. It i. also important
to note that several of thele successful
Japanese systems were designed by U.S.
vendor..
After evaluating all the comment.. the
Administrator has concluded that the
experience with system. in Japan i.
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 sy.tem could
not be accomplished, e.pecially at
utilities burning high.sulfur coal and
located in areas where rainfan into the
sludge disposal pond exceeds
evaporation from the pond. It i8
important 10 note that neither the
proposed nor final standards require
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
33593
cIo.'ed-loop operation of the FGD. The
cornmenters 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 oC 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
disposal system are properly designed.
If a water purge is necessary to control
chloride buildup. this stream can be
trell ted prior to disposal using
commercially available water treatment
methods. as discussed in the report
"Controlling SO. Emissions from Coal-
Fired Steam-Electric Generators: Water
Pollution Impact" (EPA-600/7-71HJ45b).
Two comments endorsed Goal
cleaning as an SO. 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 SO. Emission
Control" (EPA-600/7-71H)34). The
Administrator does not consider coal
cleaning alone as representing the best
demonstrated system Cor SO. emission
reduction. Coal cleaning does offer the
following beneCits when used in
conjuction with an FGD system: (1) the
SO. 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 oC the Coals of the
United States," Bureau of Mines Report
of Investigations/1976. RI~118). 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 Crom developing into
undesirable sources of energy waste, the
amount of crushing aad the separation
bath's specific gravity must be limited to
reasonable levels. The Administrator
has concluded that crushing to 1.5
inches top size and separation at 1.6
specific gravity represents common
practice. At this level. the sulfur
reduction potential of coal cleaning Cor
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 oC 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 lllinois-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 SO. Emissions from Coal-
Fired Steam-Electric Generators: Water
Pollution Impact" (EPS-600/7-71HJ45b)
and "Flue Gas Desulfurization Systems:
Design and Operating Considerations"
(EPA-600/7-78-{J30b) 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-
6OO/7-78-{J32b) and "Flue Gas
Desulfurization Systems: Design and
Operating Considerations" (EPA-600/
115
7-7-78-{J30b) also acknowledge thaI gO
percent SO, removal (or any given le\'el)
is more difficult when burning high-
sulfur coal than when burning low.sulfur
coal because the mass oC SO, that T:"ust
be removed is greater when high-sulfur
coal is burned. The increased load
results in larger and more complc, FeD
systems (requinng higher liqUld-to-~.jS
ratios. larger pumps. etc]. Operation of
current FeD 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 hl~h-
sulfur coal. Recent experience at TVA.
Widows Creek No.8 shows that FeD
systems can operate successfully at high
SO, 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
--..ss 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 oC 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 FeD
system by reducing the variability of
sulfur loading in the inlet flue gas. Coal
blending may also be useful in reducmg
short-term peak SO. concentrations
where ambient SO. 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 oC
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 matenals 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 supportir,g 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 problem..
LaCygne Unit No.1 burns high-sulfur (5
percent) coal, uses one of the earlier
FGD's installed in the U.S.. and reduce.
SO. 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 10w-8ulfur coal (0.8 percent).
Sherburne No.1, which began operating
early in 1978. had 93 percent availability
in both 1977 and 1978. Sherburne No. 2.
which began operation In late 1978 had
availabilities of 93 percent in 1977 and
94 percent in 1978. Both of these systems
include spare modules to maintain these
hi~h availabilities.
Several camments were received
exprl'ssing concern over the increased
water use necessary to operate FGD
systl'ms at Ulililtes located in arid
reg'nns. The AdmilJlstrator believes that
wa ler avaIlability is a factor that limits
power plant siting but SInce an FGD
s\'stem 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.
,\ :ew commenters cnltcized EPA for
not .nsldenng amendments to the
Fed iJ Water Pollution Control Act
(nOl 'he Clean Water Act). the
Resuvce 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
Adrmnistrator believes that the impacts
of Ihl'se Acts have been taken into
cunslderation in Ihis rule-making. The
econumic impacts were estimated on the
basis of requirements anticipated for
power plants under these Acts.
Various comments were received
regarding the SO. 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 SO. removal
exists. One comment was received
stating that 95 percent SO. removal
should be required. The Admini6trator
concludes that higher SO. removals are
achievable fot low-sulfur coal which
was the basis of this comment. While 95
percent SO. 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 SO. 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 SO. standards
were based upon the conclusion that
they were achievable with a well
designed. operated. and maintained
FGD system. At the time of propola!. the
Administrator believed that lime and
limestone FGD syslems 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 fOF
attainment of the Itandard, 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
penods at facilities when low-sulfur
coal is burned. In addition, greater than
90 percent SO. removnl !ias been
de~onstrated over long-term operating
pen ods 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
116
consideration. Five commercial dry SO.
control systems are currently on order:
three for utility boiler. (4~MW, 455-
MW, and 550-MW) and two for
industrial applications. The utility Units
are designed to achieve 50 to 85 percent
reduction oft a long-term average basis
and are Icheduled to commence
, operation in 1981-1982. The design basis
for these units is to comply with
applicable State emission timitations. 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
pres.ented in the background docum"nt
dealt with prototype units. Pilot scale
data and estimated costs of full-scale
dry scrubbing systems offer promise of
moderately high (7~5 percent) SO.
removal a' costs of three-fourths or less
of a comparable lime or litnestone FGD
system. Dry control system and wet
control system costs are approximately
equal for a 2-percent-sulfur coal. With
lower-sulfur coal.. dry contrals are
particularly attractive, not on~ because
'they would be le8s 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 materialtnal
can be more ealily 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
concentration. before the control
systems were 800 ppm So. and an
average of 2 gr/acf particulate mall!'r.
With lime as the sorbent, the control
system removed over 86 percent SO,
and 99.96 percent particulate mailer at a
stoichiometric ratio of 2.1 meles of lime
absorbent per inle! mole of SO,. When
the spent lime dust was recirculated
from the bag filter to the lime slurry reed
tank, SO. removal efficiencies up t~ 90
percent ware obtained at stoichiometric
ratios of 1.3-1.5. With the lime
recirculation process. SO. removal
efficiencies of 70-60 percent were
demonstrated at a more economical
stOIchiometric ratio (about 0.75). Similar
tests were performed at the Leland aIds
Si<:tion using commercial grade lime,
Based upon the available informat;on
the Administrator has concluded thii~ 70
percent SO. removal using lime as the
reactant is technically feasible and
economically attractive in comparison
to wet scrubbing when coals contaimng
less than 1.5 percent sulfur are beIng
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Federal Register / Vol. 44. No. 1i3 / Monday, June 11, 1979 / Rules and Regulations
33595
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 tha final form of the standard
in order to provide an opportunity for
their development on low-sulfur coals.
A ~'e!,Qging Time
Compiance with the final SO.
standards is based on a 36-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 syslem on a 55O-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 SO. 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 tha t
quoted SO. removal efficiencies were
based on testing modules. EPA found
through a survey of vendors that many
would offer 90-95 percent SO. removal
guarantees based upon their usual
acceptance test criteria. However. the
averaging time was not specified. The
Industrial Gas Cleaning Institute (lGCI).
which represents c.ontrol equipment
vendors. commented that the control
equipment industry has the present
capability to design. manufacture, and
install FGD control svstems that have
Ihe capability of attaining the proposed
SO. 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 3O-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 scate FGD systems at 500-
and 400-MW stations indicates that
variations in FGD operation make it
extremelf 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 detennination of
what the appropriate averaging time
should be.
The Administrator has thoroughly
reviewed the available data on FGD
perfonnance 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 3O-day rolling average
ra ther 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 perfonnance of an FGD system.
allows adequate time for owners or
operators to respond to operating
problems affecting FGD efficiency.
pennits 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 SO..
Emission Limitation
In the September proposal. a 520 ng/'
(1.20 lb/million Btu) heat input emission
limit, except for 3 days per month. was
specified for solid fuels. Compliance
was to be detennined 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
117
investigated ceilings lower than the
proposal. In looking at these
alternatives. the intent was to take full
advantage of the cost effecl1\'eness
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 now a
widespread practice, it was thought th3t
Eastern coal production would not be
seriously impacted by the lower
emission limit. Analyses using an
econometric model of the utility sector
confinned 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 washln!!,
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 "Is-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 Weslern
Kentucky) and the Northern
Appalachian (Ohio. West Virginia. and
Pennsylvania) coal regions. Recogmz:ng
the importance of discussion. the
Administrator invIted representatives
from the Sierra Club. the Natural
Resources Defense Co uncI!. [he
Environmental Defense Fund. the Utility
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Air Regulatory Group, and the United
Mine Workers of America. 81 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 ngll (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 ngIlIO.80 Ibt
million Btu) limit, less than 5 percent of
the reserves in each of these regions
would require, sreater 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
fu ture 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 ltudy
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
cleamng technolo8Y. The National Coal
Association acknowledged thaI crushing
to 1.5-lnch 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
handl:n~ problems and great expense.
In order to explore Further the
potential For dislocations in regional
coal markets. the Admimstrator
concluded that actual bU~'lng practices
of ullittles rather than the mere techmcal
usab.lity of coals should be considered.
This "dd!tional analysis identified coals
that r .ght not be used becacse of
cons. . alive utihty attitudes toward
scrul., 19 and the degree of risk that a
uldi'l 0 'ould be willing to take in bUYing
coal 10 ,neet the emission hmlt. This
ana:) ,IS was perF;:Irmed in a similar
manner t;:l the analysis described above
except that t\\'o additional assumptions
were made: (1) utilities would purchase
coa: that would provide about a 10
percent margin below the emission limit
;n order to minimize risk. and (2) utiltties
would purchase coal that would meet
the emission limit (with margin) with a
90 percent reduction in potential SO.
emissions. This aSlumption reflects
utility preference for buying washed
coal for which only 85 percent scrubbing
is needed to meet both the percent
reduction and the emiuion limit as
compared to the previoul assumption
that utilities would do 90 percent
scrubbing on washed coal (relulting in
more than 90 percent reduction in
potential SO. emissions). Thle analyele
was performed ueing EPA data at 430
ng/J (1.0 Ib/million Btu) and 520 ng/J
(1.20 Ib/million Btu) monthly emission
limite. The results revealed that a
significant portion (up to 22 percent) of
the high-sulfur coal reservee in the
Eastern Midwest and portions of
Northern Appalachian coal regions
would require more than a 90 percent
reduction if the emieeion limitation was
establiehed below 520 ngll 11.20 Ibt
million Btu) on a 3o-day rolling average
basie. Although higher levele of control
are technically feasible, conservatism in
utili ty perceptione of scrubber
performance could create a eignificant
disincentive against the use of these
coale and dierupt the coal markets in
these regione, Accordingly, the
Administrator concluded the emission
limitation should be maintained at 520
ngll (1.20 lb/million Btu) on a 3O-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 highpr sulfur coals.
F!.J1l Versus Partial Control
In September 1978. the Administrator
proposed a .full or uniform con trol
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 tbe
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-suliur 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 legielative
history of Section 111 of the Clean Air
Act Amendments of 1977 to bolster their
arguments. Particular attenlton was
directed to the Conference Report which
says in the pertinent part:
118
In eltablilhina a nBtional percent reduc:loll
for new fOSlil fuel-fired loureel. the
confereel agreed thai the Adminiltrator may.
in hil dilcretion. let a ran8e of pollulant
reduction that reflectl varying fuel
characterlltic.. Any departure from tha
uniform nBtional percenlase reduction
requirement. however. mUlt be accompanied
by a findinS tha t luch a deperture doel nol
undermine the balic purpoBes of the Houle
provilion and other provisionl of the act,
IUch al maximizins the ule of locally
available fuels.
Comments Fal'oring Full or Uniform
Control. Commenters in favor of full
control relied heavily on the slatutory
presumption in favor of a uniform
application of the percentage reductiun
requirement. They argued that tha
Conference Report language, ". . . the
Administrator may, in his discretion, set
a range of pollutant reductiori that
reflecte varying fuel
charac"terietice. , , ," merely reflects the
contention of certain conferees that low-
eulfur coale may be more difficult 10
treat than high-sulfur coale. This
contention, they Blsert. 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 bBlis for applying a
lower percent reduction for such coals.
These commenters further maintain
that a uniform application of the perrent
reduction requirement is needl'd to
protect pristine areas and national
parks. particularly in the West. In dOlOg
so. they note that emissions may be lop
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 besl
available control technology. They also
contend that the adoption of a partial
approacb may serve to undermine th~
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 10wN
emissions. They maintain thaI these
lower emissions are significant in ter-ns
of pubiic health and that such
reductions should be maximized.
particularly in light of the Nation's
commitment 10 greater coal use. Thel'
also assert that a uniform standard i~
clearly affordable. They point out that
the incremental increase in costs
associated with a uniform standard is
small when compared 10 total ulllit\'
expenditures and will have a mjni~dl
impact at the consumer level. They
further maintain that EPA has inflatl'd
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Federal Register I Vol. 44. No. 113 I Monday, June 11. 1979 I Rules and Regulations
33597
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
as!lociated 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 SO. emissions with about a
280 ng/J (0.65 Iblmillion BIu) 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 Partial or
Variable Cantral. 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
Aciministrator 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 penally. 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-altainment 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 SO. control systems which they felt
held consIderable promise for bringing
about SO. 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,jf 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). pres en ted detailed
results of analyses that had been
conducted for them. UARG analyzed a
standard that required a minimum
reduction of 20 percent with 520 ngl'
(1.20 lblmillion BIu) 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 Ibl
mil,lion BIu) 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
119
percent minimum control requirement.
and a variable control option which
specified a 520 nglJ (1.20 lb/million Btu)
emission limitation with a 90 percent
reduction in potential SO. emissions
except when emissions to the
atmosphere were reduced below ~60 -;'.?I
J (0.60 lblmillion Btu), when only a ~o
percent reduction in potential 50.
emissions would apply. Under the
variable approach, plants firing hlgh-
sulfur coals would be required to
achieve a 90 percent reduction in
potential emissions in order to comply
with the emission limitation. Those usmg
intermediate and low-sulfur content
coals would be permitted to achle\'e
between 7Q and 90 percent, provided
their emissions were less than 260 nglJ
(0.60 lb/million BTU).
In rejecting the minimum requirement
of 20 percent advocated by UARG. the
Administrator found that it not onlv
resulted in the highest emissions. but
that it was also the least cost effechve
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 bypa88 uncontrolled flue
gases around a malfunctioning FOD
system provided (1) the FGD system hds
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 umt 111
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 15 to
encourage power plant owners and
operators to install the best available
FGD systems and to implement dfective
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33598
Federal Register I Vol. 44, No. 113 I Monday, June 11. 1979 I Rules and Regulations
otLration and maintenance proccdures
OJ! not to create power supply
rJosruptions. FGD systems with spare
fGD modules and FGD modules with
spare equipment compone;,ts have
gr~ater capability of reliable operation
thn systems without spdre.. Effective
control and operation of FGD systems
by er.gineering supervisory personnel
experienced in chemical process
opera tions 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 fea!ures. the
Administrator believes that their use
will make compliance with the
stJndards easier. Malfunctioning FGD
systems are not exempt from the SO.
standards except during infrequent
power supply emergency periods. Since
lr.e exemption does not apply unless a
spare module has been installed (and
opera ted). a spare module is required for
~e exemption to apply. Because of the
disproportionate cost of installing a
sfJare module on steam generators
having a generating capacity of 125 MW
or iess, the standards do not require
them to have spare modules before the
emergency conditions exemption
appLes.
The proposed standards included the
requiremer.t that the emergency
condition exemption apply only to those
facilities which have installed a spare
fCD system module or which have 125
"tVI! 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
Ihls determina tion is to be performed.
prOVISions have been added to the
regulations. This determination is not
required "nless the owner or operator of
the affected facility wishes to claim
spar~ module capability for the purpose
of ay ailing himself of the emergency
condition exemption. Should the
AJminislrator require a demonstration
of spare module capability. the owner or
o~..rator would schedule a test within 60
da~ '. for any period of operation lasting
fren :t hours to 30 days to demonstrate
tr.d' ,can attain the appropriate SO.
"'n")n control requirements when the
fa: .:1 IS operated at a maximum rate
wlthoLt usmg one of its FGD system
modules. The test can start at any time
of day and mod ales may be rotated in
ar.a nut of service. but at all times in the
Ipsl ,'''rIod one mC'dule (but not
~,'cf'''..rdy the same module) must not
b.. op..r.Jted to demonstrate spare
mod,,!£, capability
Althollgh 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 10 Bchedule the specific
date and duration of the test. A
minimum of only 24 hours of operation
are required during the tesl period
because this period of time is adequate
to demonstrate spare module capability
and il 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
otoperation 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
mod'ules 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 slipply 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 wi:! 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,R,. the failure of one coal
pulverizer) could prevent a boiler from
be:ng o?frated 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 ask..d 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 electri1:
generating capacity available in the
system. the Administrator agrees with
120
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
awnership basis for proration of electric
lapacity in several-definitions be
810dified when there are other
contractual arrangements. The
Administrator agrees with this comment
and has revised the definitions
accordingly.
One commenter asked that d..fir.il'ons
describinR "a!! electric ~ci1eratin~
equipment oWlled by the utili tv
company" specifically include
hydroelectric plants. The proposed
definitions did include these plants. 'HIt
the Administrator agrees with th!!
clarification requested. and the
definitions ha VI' been revised.
A commenter asked that the word
"steam" be rcmoved from the defini1ion
of system emergency reserves to clarify
that nuclear units are included. The
Administrator agrees with the comment
and has revised the definition.
Several comm£:nters asked that some-
type of modification be made 10 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 tl:e
suggestion of using a projected load,
which mayor may not materialize. as a
criterion to allow bypassing of SO.
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 Temoved from scrvice 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
il!1practical to take a large steRm
generating unit entirely out of .;..rvict!
whenever load demand,is exppc!"d 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 prl'posed
emergency condition provisions to give
an owner or opera tor of a unit with a
malfunctioning FGD system the option
of keepIng lor bringing) the unit into
sp;nning reserve when the unit is
needed to maintain (or ree~tablish)
system emergency reserves. During :his
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Federal Register I Vol. 44, No. 113 I Monday. June 11. 1979 I Rules and Regulations
33599
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
Cailed FGD system is inadequate. This
procedure will allow the unit to opera te
in spinning reserve rather than being
ent:rely 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
lasl 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 lolal operating hours. this revision to
allow bypassing of SO. emissions from a
unit held in spinning reserve with
reduced output is expected to have
minor impact on the amount of SO.
emi tied.
One commenter stated that the
proposed provisions would not reduce
the necessity for additional plant
capacity to compensate for lower net
reliabilily. 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
theJ'eby protects the reliability of
eleGtric service. When electric load is
shifted from a new steam-electric
genera ting unit to another electric
ger.erating unit, there would be no net
change in reserves within the power
system, Thus. the emergency condition
provisions prevent a failed FGD system
Crom impacting upon the utility
company's ability to generate \,dectric
power and prevents an impact upon
rest!rves needed by the power system to
ma:ntain reliable electric service.
A commenter asked that the definition
of uV1lilable 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
tl\rough 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 intercol\Jlected 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 con'tingent upon the
purchase of power from another
electrical generation facility. To further
clarify this rela tionship. the
121
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 damase
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 gene~ating
unit. The utility company can regulate
system load-frequency by distributmg
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 mamta mJn~
power system integrity, because tr.e
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 10 I~nore
the loss of SO. removal efficiency due :0
FGD malfunctions by reducing the ie\ ei
of electric generation from an affected
unit. This would control the amounl of
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33600
Federal Register I Vol. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
SO. emitted on a pounds per hour basis.
but .vould also allow and exemption
from the percentage of SO. removal
spl'clfied by the SO. standards. The
Aciministrator believes that allowing
this l'xemption is not necessary because
load can usually be shifted to other
ell'ctric 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 commenter.
np.gl~ct of the FGD system would be
encouraged because an exemption
wou:d 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
the~e periods if this exemption were
allowed. The procedure soggested by
the commenter is also not necessary
bec...use FGD modules can be designed
and cunstructed 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
alta,"m!! the same percentage reduction
of SO. from the fiue gas It treats
rl'gardless of the operability of the other
modules In the system to maintain
comr'lance with the standards.
.\lthoJgf, the l'ffic1ency of more than one
FGD 'TIodule may occasionally be
affected by certain l'quipment
maif JnctlOns. a properly designed FGD
S} stem has no routine need for an
exemption from the SO. percentage
rl'du( :lOn requIrement wr.l'n the unit is
opera'cd at reduccd load. The
A~m:nlstrator has conch:ded that the
f:~Ji rp~ulations provide sufficlCnt
rle;o(lbl!,ty for i.lddressm~ reD
mai'c"c!Jons and ,hat an exemption
from. Ie percentage SO. removal
req~""'nent is not necessary 10 protect
e;ecl . service reliab:lHY or to maintain
cor.,~ iDce with these SO, standards.
p,,"."
.::e .\Tolter Standard
Ti,,, final 5tandard limits particulate
r,;.' ~'.'" t'~l;'Slons 10 13 n~;J (0.031bl
:111::" " cHul nt'at IClpUt and IS based on
I':~ J;'p.ILatiGn of ESP or \;agnouse
conl[OI technolo~\' 1he Laal s:andard is
Ihe same 3S the ~ropcsed. The
.\dm.:;i>lr~tor has concluded thaI 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 enviommental
impacts. and energy requirements) and
that 13 nglJ (0.03 lblmillion 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 propoaed
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 nglJ
[0.10 lb/million Btu) heat input which ia
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 t.hat ESP and baghouse
control systems are capable of
performing at the 13 nglJ (6.03lb/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 !.Jaghooses are designed and
constructed in modules rather than liS
one large unit. there should be no
technological barriers to designing and
constructinlj utility-sized facilities. The
largest baghouse-controlied. coal-fired
power plant for which EPA had
er.lIssion test data to support the
proposed standard was 4~ MW. Since
the standards were proposed. addi:ional
infarma tion has becorr " a vailaole which
supports the .$,.dmimslrator's posilicn
t!:at ba!:houses are demonstrated fJr all
sizes of power plants. 1 wo large
ballhoose-con!roHed. cI.al-fired power
plants have recenll..- initiated
operations. EPA ha~ obtained emission
data for (lae of Ih~se ur:i!s. This unit has
achieved particulate matter emi~sicn
levels below 13 nglJ (0.03 Ib/million Btu)
heat input. The baghollse svstem for this
faclln}' has 28 mocules rated at 12.5 l\!W
122
capacity per module. This supports the
Administrator's conclusion tl:at
baghouses are desiqned and constructed
in modules rather than as one large \IOit.
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
applica~ion at this time and.
recommended that EPA gBther one year
of data from 1000 MW of baghouse
installations to demonstrate that
baghouses can operate reliably and
achieve 13 nglJ (0.03 Ib/milJion St!l) heat
input. The standard would remain at ~1
to 34 ng/l [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 supportet.l
the proposed standard of 13 ng/l (0.03
lblmillion 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 s}'3tcm manufacturers
indicated that 13 n~1J (0.03 lb/million
Btu) is te('hnically achievable. The trade
association further indicated the
proposed standard i3 technicallv
achievable fer either high- or lo~v.sulfl:r
coals. through the use of baghouses.
ESPs, or wet scrubbers.
A number of comlT.enters
recommended that the proposed
standard be lowered to 4 ngl! I!J ollbl
million Btu) heat input. This group of
commenters presented addilional
emission data for utility baghouse
control systems to s!loport lheir
recommendation. The data submitted by
the Lommenters \'IIere not available al
the lime of proposal and were iur utiLty
units of leu than 100 ~.!W,electflcal
output capacity. The commente~s
su~.~csted th:.>t a 4 rg/l U).01 Ihi mdlion
Btu) heat Input standard is achie.able
based on ba~hol:se techno!,,<;)'. dnd they
s:l~gested tl:dt a ~'3n,jard baseu on
b.Jghousl' techno!o~y wouid be
C0,~s;stent "11h the techn<.ilogy-f"lcin,:
nature of ~ecti(\n 111 of the Act. The'
Administrator believes tho! rhe
availilble data base for bagl;ousp
performance SUDports a standard of 13
nglJ (0.03 Ib/million 8tu) heal irput but
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Federal Register I Vol. 44, No. 113 I Monday, June 11. 1979 I Rules and Regulations
33601
dot's not support a lower standard such
as 4 ng/l (O.Ollb/million Btu) heat input.
One commenter suggested that the
standard should be set at 26 ng/J (0.06
lb/million Btu) heat imput so that
particulate 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 oil-fired
utiJity 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 lb/million Btu) heat input
from the combustion of subbituminous
coal and 260 ng/J (0.60 Ib/million Btu)
heat imput from the combustion of
bitun»nous coal. based on a 3O-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
prf'amble. 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 fur coal might seriously restrict
the flexibility boiler operators need
during day-to-day operation. For
exumple. several clJmmenters noted that
on some boilers the control of boiler
tube slagging may periodically require
increased excess air levels, which. in
tUnl. would increase NO. emissions.
One commenter submitted data
indicating that two modern Combustion
En~ineering (CE) boilers at the Colstrip.
Montana plant of the Montana Power
Company do not consistently achieve
the proposed NO. level of 210 n8/J (0.50
Ib/million Btu) heat input on a 24-hour
basis. The Cob trip boilers burn
sub bituminous coal and are required to
comply with the NO, standard under 40
crn Part 50, Subpart D of 300 nglJ (0.70
Ib/million Dtu) 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
26 months of Colstrip data indicating the
number of 24-hour averages per month
above 210 ng/J (0.50 lb/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 abiJity
of modern utility boilers to continuously
achieve the NO, emission limits of 210
and 260 nglJ (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 nglJ (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 nglJ
(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 nglJ [0.60
Ib/million Btu) heat input for bituminous
coal ov 210 ng/J (0.50 lb/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
opera tion of a utili ty-size boiler. In the
Administrator's judgment, this emission
123
variability adequately represents
slagging conditions. coal variability.
load changes. and 'other factors tha t may
influence the level of NO, emissions.
(4) The variability of continuously
monitored NO. data is sufficient to
cause some concern over the abihty uf a
utility boiler that burns solid fuel to
consistently achieve a NO. boiler d,'sl~'1
limit. whether 300. 260. or 210 nglJ (0.70.
0.60. or 0.50 lb/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 :\iO,
data from boilers manufactured by
companies other than CEo the data frum
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
opera tion of a boiler (e.g., slagglng.
variations in fuel quaJity. and load
reductions) are simllar for all fuur
manufacturer designs. These condltluns.
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, mom tors have
not passed certification tests. In April
and June of 1976 EPA conducted a
detailed evaluation of these monitors.
The evaluation led the Admimstrator to
conclude that the mom tors were
probably biased hIgh. but by less th..n
21 ng/J (0.50 Ib/million Btul heat Input.
Since this error is so small (less than ;0
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 achlCve the
proposed standards. Although most of
the available NO, test cata are from CE
boilers. the Administralor believes that
all four of the boiler manufacturers wlil
be able to supply bollers capable of
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33602
Federal Register I Vol. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
:lchievlng the standards. This conclusion
IS st;pported with (1) emission test
rp.~,"i:s from 14 CEo seven Babcock and
V'llcox (BdrW). three Foster Wheeler
(FW:. and four Riley Stoker (RS) utility
boilers: (Z) 34 months of continuously
mO:1Itored NO. emission data from
~tven CE boilers: and (3) an evaluation
of plans under way at B&W. FW. and R5
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-
te:m adverse side effects.
Another iSllue raised by commenters
ccncerned 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 Admlnistrator's judgment. the
emission limit. for NO. are achievable
with properly designed and operated
boilers burning any coal. regardles. of
its mtrogen content. As evidence of this.
three of the six boilers tested by EPA
burned coals WIth nitrogen contents
above averag~. and yet exhibited NO,
emISSion levels well below the
s:andards. The three boilers that burned
coals with lower nitrogen content. al.o
exhIbited emission levels below the
standards. The Administrator believes
this :5 evidence that at NO, levels near
21(1 and 260 ngl! (0.50 and 0.60 Ibl
mlilicn Btu) heat input. factors other
than f'lel-nitrogen-content predominate
in determining final emission levels.
A number of commenters expressed
concern over the potential for
accelerated tube wastage (i.e..
corrosIOn) dunng operation of a boiler in
compliance with the proposed
standards. Almost all of the 300-hour
and JO-day coupon corrosion tests
ronducted during the EPA-sponsored
lu\\ '\0, studies indicate that corrosion
rate iecrease or remain stable during
ope! Ion of boilers at NO, levels as low
as the, e required by the standards. In
the 'e\" Instances where corrosion rates
incrp Ised during low-NO, operation. the
Incrp]!eS were considered minor. Also.
CE ~ B guaranteed that Its new boilers
\\ 1:1 .chlp.\ p the ~,O, emission limits
",th,'utlnc.rt'aspd tube corrosion rates.
..\.~":~"r botler !':1anufacturer. BS.W. has
developed new 10w-e:msslOn 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 boiler.
subject to the 300 ngll (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 260 ngll (0.60 lblmillion Btu)
heat input on a range of bituminous
coals. Three of the .ix utility boilers
tested by EPA burned bituminous coal.
(Two of these boilers were
manufactured by CE and one by BAW.)
In addition. the Administrator has
reviewed continuously monitored NO.
data from two CE boilers that bum
bituminou. coal. Finally. the
Administrator ha. examined NO.
emission data obtained by the boiler
manufacturers on seven CEo four B&W.
three FW. and three RS modern boilen.
all of which burn bituminous coal.
Nearly all of these data are below the
260 ng/) (0.60 Ib/million Btu) heat input
standard. The Administrator believes
that these data provide adequate
evidence that the final NO. standard for
bituminou. coal is achievable by all four
boiler manufacturer de.i!!ns.
An iS8ue raised by several
commenters concerned the use of
catalytic ammonia injection and
advanced low-emillion burners to
ac/ueve NO. emission levels as low as
15 ng/J (0.034 :b/rnillion Btu) heat input.
Since these control. are not yet
available. the commenters
recommended that new utility boilers be
desill.ned with sufficient space to allow
for the installation of ammonia injection
and advanced bumen in the future. In
the meantime the commenters
recommended that NO, emissions be
limited to 190 ng/J (0.45 lb/mil!ion Btu)
heat input. The Administrator believes
that the technology needed to achieve
NO. levels as low as 15 ngll (0.034 lbl
mlllion Btu) heat input has not been
adequately demonstrated at this time.
Although a pilot-scale catalytic-
ammonia-injection .ystem ha.
successfully achieved 90 percent NO.
removal at a coal-fired utility power
piant in Japan. operation of a full-scale
ammonia-injection system has not yet
been demonstrated on a Iilr!;e coal-fired
boiler. Since the Clean Air Act requires
that emission conlroltechnology for new
source performance standards be
124
adequately demonstrated. the
Adm\nistra:or cannot justify
establishing a low NO. standard based
on unproven tE'chnolo~y. Similarly. the
Administrator cannot justify reqUlri!'g
boiler designs to provide for possible
future installation of unproven
technology.
The recommendation that NO.
emissions be limited to 190 ngll (0.~5 Ibl
million Btu) heat input is based on boiler
manufacturer guarantees in California.
(No such utility boilers have be'!n bUIlt
. as yell Although manufacturer
guarantees are appropriate to consider
when establishing e:nissicn limits. they
cannot always be used as a bag;s for a
standard. As several commenters have
noted. manufacturers do not alwavs
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 lblmillion Btu)
heat input can be continuously achieved
without adverse side effects when a
wide variety of coals are burned.
Regulatory Analysi.
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 hu extensively
analyzed the costs and other impacts of
these regulation.. These analyses. which
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 t:'Ile of
proposal (see STUDIES. 43 FR 42171).
this preamble. and the additional
background information docul1'!'nt
accompanying this action ("Electric
Utility Steam Generating Units.
Background Information for
Promulgated Emission Standards." EPI\-
450/3-79-021). Due 10 the volume of Ihis
materidl and its continual development
over a period of 2-.1 years. it is not
practical to consolidate all analyses IOto
a single document. The following
discussion gives a summary of the most
slgr.ificant alternatives con.idered. The
rationale for the action taken for each
pollutant being regulated is given in a
previous section.
In order to determine the appropri
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Ru!~s and Rc~ulatjons
:;,~C;[;1
";, '''''''1;.\ char,,,.terisilcs f)f lile ullilty
inllu~try in future ~ ears. These muuc;,
pr.'juGt tile environmental. economic.
,:n,1 energy impacts of alternali\'2
sknJurds fer the e!ec!ric ut!iity
i::Gustry, The major analytical efforts
lock place in three phases as descnbed
below.
Phose 1. The initial effort comprised a
pr"Jiminary analysis completed in April
1978 and a revised assessment
corr.;:;le!e:l in A~gust 1978. These
a;I.11yses were presented in the
Se:J!ember 19. 1978 Federal Register
prc:posal (U FR 42154). Corrf'ctions to
th,~ September prop03al package and
adiil10nal information was published on
November 27.1978 (43 FR 55258).
Further details of the analyses can be
found in "Background Information for
Proposed SO. Emission Standards-
Supplement." EPA 450/2-78-007a-1.
Phase 2. Following the September 19
proposal. the EPA staff conducted
additional analysis of the economic.
environmental. and energy impacts
as;;ociated 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
eaLh 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
DeGember 8. 1978 (43 FR 7834).
Phase 3. Following the public
hel;rings. 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 i:lgher emission limits.
~ecO!1dly. several comment3 were
",cl)ived from the public regarding the
pot,~ntial of dry sulfur dioxide scrubbing
systems. The phase 1 and phase 2
an"lyses had assumed [hat utilities
would use wet scrubbers only. Siuce dry
scrubbing costs substantially less then
wel scrubbing. adoption of the dry
tc~hnolagy would substantially change
I~.p. c:,:onomic. energy. and
environmental imp3cts of :1lternati\'e
s'lifur dioxide standards. Hence. the
phase 3 analysis focc:;ed on Ihe impacts
of alternative standarcs under a range
of emission ceilings a~suming 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 w~re 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. the present value costs of tbe
alternatives were calculated.
The effects of the alterna tive
proposals on energy production and
consumption were also analyzed.
National coal use WIIS 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 t)l'e~ 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
condl tions.
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 consid!:!ration 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
125
t~ccnomic.bac;ed dedsl'JO r.nlt~r! I ,~'
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31604
Federal Register I Vol. 44. No. 113
Monday. June 11, 1979 I Rules and Regulations
equal to the moderate growth
prfJjections 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 opera tinS 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 emiuiOJl
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
shipped Ions distances. The auumed
mininslabor 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
Dumber of comments from the public
regarding the modeling auumptions.
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 repres~ntatives from the Department
of Energy, Council of Economic
AdvIsors. Council on Wage and Price
Stabillly, and others. The sroup
reviewed model results to date.
identlfied the key inputs, specified the
assumptions, and identified the critical
parameters for which the degree of
une, 'tainty was such that sensitivity
ano ,es should be performed. Three
mar. s of study resulted in a number of
chan, 's which are reflected in Table 1
and j'3cussed below. These
assumptions were used in both the
phdse 2 and phase 3 analyses.
Af~er more evaluation. the jOint
workln~ group concluded that the oil
pnces 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 sovemmental entitie.
concerned with projecting oil price.. The
oil price sensitivity enaly.is was PJ!rt of
the phase Z analy.i. which wa.
distributed at the public hearing. Further
details are available in the draft report,
"Still Further Analy.is of Alternative
New Source Performance Standards for
New Coal-Fired Power Plant. (docket
number IV-A-5)." The analysi. showed
that while the variation in oil price
affected the masnitude of emillions.
costs, and energy impacts. price
variation had little effect on the relative
impact. of the various NSPS alternatives
tested. Based on thi. conclusion. the
higher oil price was selected for
modelins purposes since it paralleled
more clo.ely the middle ranlle
projections by the Department of
Energy.
Reassellment of the assumption.
made in the phase 1 analy.i. also
revealed that the impact of the coal
wa.hing credit had not been con.idered
in the modeling analy.i.. Other credit.
allowed by the September propoaal.
such as sulfur removed by the
pulverizer. or in bottom ash and flya.h.
were determined not to be sisnificant
when viewed at the national and
relJionallevel.. The coal wa.hing credit.
on the other hand. wa. found to have a
significant effect on predicted emission.
level. and, therefore, was factored into
the analysi..
As a result of this reassessment.
refinements also were made in the fuel
gas deiulfurization (FGD) cost.
assumed. These refinements include
chanse. in sludae disposal costs, energy
penalties calculated for reheat. and
module sizinS. In addition, an error was
corrected in the calcula tion of partial
scrubbinS costs. These changes have
resulted in relatively higher partial
scrub binS costs when compared to full
scrubbing.
Chanses were made in the FGD
availability auumption also. The pha.e
1 analysis assumed 100 percent
availability of FGD systems. Thi.
assumption, however, was in conflict
with EPA's estimates on module
availability. In view of this. several
alternatives in the phase Z analysi. were
modeled at lower system availabilities.
The assumed availability was consi.tent
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 resulation. The analysis
126
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 po.tulated that the lower reliability
as.umption would produce sreater
adverse impect. on full control than on
partial control option.. the relative
differences in impact. were found to be
in.isnificant. Hence. the workins group
discarded the ~liability i.sue as a major
consideration in the analyzing of
national impact. of full and partial
control options. The Adminiatrator still
believe. that the new'!r approach better
reflects the performance of well
desisned. operated. and maintained
FGD sy.tems. However, In order to
expedite the enalyse., allsubselluent
alternative. were analyzed with an
assumed system reliability of 100
percent.
Another adju.tment to the analysis
wa. the incorporation of dry SOl
scrubbing system.. Dry .crubben were
assumed to be available for both Dew
a..d retrofit applications. The coat. of
these system. were estimated by EPA'a
Office of Re.earch and Development
baeed on pilot plant studies and
contract prices for syatem. cWT1lntly
under con.truction. Based on economic
analysis. the u.e of dry scrubbers wa.
assumed for low-.ulfur coal (less than
1290 nglJ or 3 Ib SOl/million Btu)
applications in which the control
requirement was 70 percent or less. For
higher sulfur content coals. wet
scrubbera were assumed to be more
economical. Hence, the scenarios
characterized a. u.ing "dry" costs
contain a mix of wet and dry technology
whereas the "wet" scenarios assume
wet scrubbing technology only.
Additional refinement. 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 lell significant
adju.tments were made. These included
..dju.tments 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 19;"5
dollars. ft should be uRderstood that all
reported co.t. include the costs of
complying with the proposed partlcu.at£
matter standard and NO. standards, dS
well a. the sulfur dioxide alternatiwi,
The model does not incorporate the
Agency's PSD regulations nor
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Federal Register / Vo\. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
33605
[orthcoming requirements to protect
visibility.
Public Comments
I~ollowing the September proposal. a
number of comments were received on
the impact analysis. A great number
f"cused on the model inputs. which
WHre reviewed in detail by the joint
working group. Members of the joint
working group represented a spectrum
of expertise (mergy, jobs. environment.
inflation, commerce). The following-
paragraph. di.cuss only those
comments addressed to parts of the
analysi. which were not discussed in
thp. preceding section.
One commenter suggested that the
costs of complying with State
Implementation Plan (SIP) regulation.
and prevention of significant
deterioration requirements should not
be charged to the standards. These cost.
are not charged to the standards in the
analysM. Control requirements under
PSD are ba.ed on site specific, case-by-
case decisions for which the standard.
serves as a minimum level of control.
Since these judgments cannot be
forecasted accwately. 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
SCt!Darios modeled. Thus. any forecasted
CO!.t differences among alternative
standards reflect difference. in utility
expenditures attributable to changes in
th.' standards only.
Another commenter believed that the
time horizon for the analysis (1990/1995)
WIIS too short since most plants on line
at that time will not be subject to the
re\ ised sl!lndard. Beyond 1995. our data
show that many of the power plants on
line today will be approaching
retirement age. As utilization of older
capar.ity declines. demand will be
picked up by newer. better controlled
p!ants. As this replacement occurs.
nalional SO. emissions will begin to
dedine. Based on this projection. the
Administrator believes that the 1990-
19(;5 time frame will represent the peak
ye:!rs for SO. emissions and !s.
thl'refore. the relevant time frame for
thi.; analysis.
Use of a higher general inflation rate
was sug.qested by one commenter. A
distinction must be made between
genf!ral inflation rates and real cost
I'se ala tion. Recognizing the uncertainty
of future inflation rates. the EPA staff
conducted the economic analysis in a
ma:1ner that minimized reliance on(this
assumption. All construction. operating.
IInd fuel r.osts were expressed as
con9!ant year do\!ars and therefore the
analysis is not affected by the infla tion
rate. Only real cest escalation was
included in the economic analysis. The
inflation raies will have an im?2ct on
the present value discount rate chosen
since this factor equals the inflation rate
pins 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 analylris. 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 [fable 5)
were concluded to be equal to the
monthly resfdential bills ("Economic
and Financial Impacts of Federal Air
and Water Pollution Controls on the
Electric Utility Industry." EPA-230/3-
76/013. May 1976).
One utility company commented that
the model did net 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.
DeveloDment of these curves took into
consideration representative daily load
curves. tradition..l utility reserve
margins. seasonal demand variations.
and historical generaticn data. The
Administrator believes that this
approach is adequate for forecasting
Ions. term impacts since it plans for
meetlDg 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 roBing
averages. and each standard was
analyzed with a particulate standard of
13 ng/! (0.03 Ib/million Btu] and the
proposed NO. standards. The Cull
127
control option was specified as a c.';o
ng/' (1.2 Ib/mllilOn Btu) emlS',on I nil
with a 00 percent reducticn ID pato-."."
SO, emissIOns. The other opt:cns ,'Cf~ the
same as f\;11 c.:Introl except wnen :!;~
emissions to the atmosphere are
reduced below 260 ngll [O.6Ib/ml:",n
Btu) in which case the minimum r.'ccent
reduction requirement IS reduced. The
variable control O'1tion reouires a ~o
percent minimum reductic~ and the
partial control option has a 33 percer:t
minimum reduction requirernl'nt. The
impacts of each option were forecast
first assuming the use of wet scrui;b~rs
only and then assuming introduction of
dry snubbing technology. In conlr .;sl 10
the September proposal which focuspd
on 1990 impacts. the analvtical results
presented today are for the year 19Q5.
The Administrator believes that 1995
better represents the differences among
alternatives since more new plants
subject to the standard will be on liZ1e
by 1995. Results of the 1900 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 Tabll's 2 and J.
Table 2 details the 1995 national SO,
emissions resulting from different elant
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
IIffected 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 :;oal
consumption in new plants results L'om
the increased cost of constructing and
operating new coal plants due to
pollution controls. With these increaseJ
costs. the !Dodel predicts delays '11
construction of new plants and d~a~~es
in the utilization of these Dlar.ts :::f:n
start-up. Reduced coal C()~Sum::,t:"n by
new plants is accompanied by :!I~:'Pr
utilization of existing plants and
combustion tureines. T!:is shift cau,og
increased emissions frn;n ex:sti!1R v'"i-
and oil.fired olants. wh;ch earl:u.Jv
offsets the e~iss;on rec'"c:io,...:; ."." :P\'~d
by new plants subject to the sti1nd~cd.
Projections of 1995 regmr.ai 50,
emissions are summarized 10 T abl? J.
Emissions in Ihe East are rl'duc.ed by
about 10 to 13 percent as com~a:ed :0
p~edictions under the current stand ,res.
whereas ~Iidwestern emissions a~e
reduced only slightly. The smailer
reductions in the r-lidwest are d'Je I I a
slow growth of new coal-ilreu cap~uty.
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33606
Federal Register I Vol. 44. No. 113 I Monday, June 11,-1979 I Rules and Regulations
[n 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 aDd 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
standards. 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 end 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
na tional 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
standards. 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 mcreases in
consumption due to gas-to-oil
conversions.
Ot! consumption by utilities is
predicted to increase under all the
optIOns. Compared to the current
standards. increased consumption is
200,(,'10 barrels per day under the partial
and !riable options and 400.000 barrels
per " under full control. Oil
consu. 'ption differences are due to the
higher costs of new coal plants under
these standards. which causes a shift to
'Dore generation from existing oil plants
and combustion turbines. This shift in
!:eneration mix has Important
Implications for the decision-making
process. slDce the onlv assumed
constraint to utility oii use was the
price. For e}tample. if netional 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
standards 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 includeslevelized
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 a verage 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 iricreeses in
consumer prices due to the increased
128
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 emillions. as compared to the
current standards. These ratios are 0
measure of the cost effectiveness of the
option.. where lower ratios represent a
more efficient resource allQcation. All
the option. result in higher cost per ton
than the current standard. 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 tQn 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 valul: 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 estimale
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 controi.
and $32 billion for partial con trol.
Dry Scrubbing Results
Tables 2 through 5 also show the
impacts of the options under the
assumption that dry SO. scrubbing
systems penetrate the pollution control
market. These analyses assume that
utilities will install dry scrubbing
systems for all applications where tl:ey
are technologically feasible and less
costly than wet systems. (See earlier
discussion of assumptions.)
The projected SO. 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.
how~ver. the variable control option is
predicted to have the lowest national
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Federal Register I Vol. 44. No. 113 I ~Ionday. June 11. 1979 I Rules and Regulations
31fi07
em,ssions 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
standards. 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 thl!
Midwest and West South Central are
relatively unaffected by the options.
Inspection of Tables 2 and 3 shows
that with the dry control assumption the
corrent standard. full control. and
par tial centrol cases produce sligh tly
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
wllh dry scrubbers. The increased
variable cost of dry controls alters the
disoatch order of existing plants so that
older, uncontrolled plants operate at
relatively higher capacity factors than
would occur under the wet scrubbing
as~umption. hence increasing total
em.ssions. 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 1995.
Nalional 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,
e>.cept under a full control option where
dry controls cannot be applied to new
plants. Under the variable and partial
opt'ons 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
plams production declining and
production in the rest of West
increasing. The ameunt of western coal
shipped east under the current standard
is reduced from 122 million to 99 million
Ions (20% decrease) due to the increased
'Ise of eastern intermediale sulfur coals
fer dry scrubbing applications. Western
coal shipped east is reduced further by
(he ~evised standards, to a low of 55
million tons under full comrol. 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 1995 economic effects of these
standards 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 sa vings of
$1.4 billion in annualized costs which
equals a $14 billion net present value
savings. Variable control results in a
$1.1 billion annualized cost savings
which is a savings of $12 billion in net
present valae. 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.
Conclusions
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 SO.
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 utiliz!!d 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
129
wet and dry scrubbing assumptlcl~S
Compared to full control. var "hi!'
control is predicted 10 resuit :n 1~ G\\' :0
17 GW more coal capacity. ThIs
additional capacity repldces dirtlt'r
existing plants and compens,ltes [01' the
slight increase in emissions from 11<'\\'
plants subject to the standards. hence
ca using emissions to be less than or
equal to full control emissions
depending on scrubbing cost assumpt.nn
(i.e.. wet or dry). Partial control and
variable control produce about the same
coal capacity. but the additional 100
thousand ton emission reduction from
new plants causes lower total emiSSions
under the variable opton. R!'gionaily. all
the options produce about the same
e:nissions in the Midwest and West
South Central regions. Fun control
produces 200 thousands tons less
emissions in the West than Ihe varluble
option and 300 thousand tons less th...n
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 fuil
control with respect to costs under both
the wet and dry scrubbing assumptions.
Under the dry assumption, which the
Administrator believes reDresents the
best prediction of ulility b-ehavior.
variable control saves about $1.1 billion
per year relative to fuil control and
partial control saves an addItional 50.3
billion.
An the options have similar impacts
on coal production especially when
considering the large increase predicted
over 1975 production levels. With
respect 10 oil consumption. howev!'r. the
fun control option causes a ~oo.ooo
barrel per day increase as compared to
both the partial and variable options.
Based on these enalvses. the
Administrator has con~luded that a non-
uniform control strategy is best
considering the environmental. enp"]','.
and economic impacts at both naLo~al
and regional levels. Compared to other
options analyzed. the variable contr')l
standard presented above ad-,;',,-es the
lowest emissions i]1 an efficient manreer
and will not disrupt local or regional
coal markets. Moreover. this option
avoIds the 200 thousand barrel per dav
oil penalty which has been predJctE'd -
under a number of control options. For
these reasons. the Administrator
believes that the variable conlrol optJ'Jn
provides the best baJance of national
environmental. energy. and economic
objectives.
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33608
Federal Regi.ter I Vol. 44. No. 113 I Monday. JUJ)e 11. 1979 I Rule. and Regulations
T81118 1.-K.,. Modeling ,....",,-
-
G~ ..,. ...-.... ~ .........--...-.-....-.....-.-.----.-- "75-1815: ".8"")'.
1885-'_: 0.0'110.
Nuclear C8Q8Qty .. ""'__Oh_"_'''--'''-'-''''''''''''W''''''-''''--'''- 1M!:'7 GW.
,880: HIS.
'815: 228.
Oil one- IS ,g751.....-...--... .....-. ........ ....-......----.-- '185: SI2.1IO/bbL
'Il1O: ""'0.
,l1li: 121.00.
eool ---. ..-..... ........-.....-................--............-'- ,'110 ""' - --
Cool ""*'11- -'" ......- ._. ,,,,,,,,,,,,,""""'''''''''''''-'-''''- U.M.W. - ond,'IIo - --_.
C- cno
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Federal Register I Vol. 44. No, 113 I Monday. June 11. 1979 I Rules and Regulations
33609
T8IIIe -~ on Fueb ;" '99!Y'
L.ev'8f of controf'
1815 CutrenI - FuII- p-- v_-
- 33'" mnmum 70"'.........
-. Oty' - Oty """ Oty Wet Oty
U.8 CooI_(-
-,;
AppII8c/1iII..---.-- 388 OIl S24 C83 - 415 488 410 484
-.-....------ 151 - 381 481 488 458 452 - 450
- Gr... PI_.... 54 855 830 833 828 822 518 832 802
W........---.-.- 411 230 222 182 180 212 228 203 217
TOIII ...------- 841 l.nl 1.111 1.185 \,181 1.185 1,7.2 l,no 1.752
w..- Cool 9Npped E8II
f- -1...-.....-.......-- 21 122 88 59 55 88 59 11 70
01 ConunpIon .., -
PI_(_IIbIJCIIIy~
--.....................-.........-... 1.2 1.2 \.' ... 1.4 1.4 1.4 1.4
Cool T'----_.__..--.-- 0.2 U 0.2 0.2 0.2 0.2 0.2 0.2
TOIII ""---"'-'- 3.1 1.4 1.4 18 18 1.' \. 1.8 18
. - 01 EPA ......,.. CCInIpIeI8d In May 1879 ..- on aI - 01 512 90. 518.40. ond 521.00I11III .. "" ,..,. . 985.
1890, - 19115.~.
'Wt1ll52OnglJ -....--
. - on - so....-.g--
,- on..., so....-.g --
T8bIe &'-'995 EcoflOmlC I~'
11818 doIl8r8l
L- of conttoO'
CutrenI-
FuII-
P"",",--
33% mwwnum
v_-"'"
70% mwwnum
Wet' Oty' Wet Oty Wet Oty """ Oty
AVOf- MonGI1y R_IIII Sill. ($I
IMf1lhl.....................................-.-....-.. 153.00 552.85 5500.50 S54 45 554 15 153 95 154 30 S54 05
Il1dUoct Conou- I~CIO (SIr-.IIII.. ..,...'" 150 180 1 15 1.10 130 120
Incmmenl8l UIIIIIy CoI>d8I ExpondI-
ILl''', Cumu&81tv8 191~'"5 (S ~
""...1.... .. 3 10
Incrltm8ntaJ AnnuaJlz8d Cool (5 bol.
1"""1) .... ......................... ... ., 44 32 30 36 33
Pr."enl Value 01 IncNmental Utility
R.JVttnUII Requtt'em8n11 IS bdMo".... .. 41 45 32 31 31 33
locrnm."I" CoI, of SO I R8'CIuCIkIn ($1
10'" ..... .... 1.322 1,428 '.094 1,012 1.183 \ 038
. Rell.ln. 0' EPA anllyMl compteted In-May 1978 blsed on oH pnce. of 11290. "840. and 521 OO/bC)l '" the )'8'" '985,
1990. .nd 1995. -
. Wllh 520 ngl J rrwnmurn 8mll8On IwTvt
. e.88d on wel SO. scrubbing costa
. e.- on dry so, IICNIIbong coo.. -- -'
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33610
Federal Register I Vol. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
(sulfur dioxide only) for each 24-hour
period of operation. Continual
determination of compliance with the
p~oposed standard would have
necessitated that each source owner or
operator install redundant CMS or
conduct manual tuting In the event of
C~S 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-che-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 it impouible for the test
team to obtain the required data. The
Administrator agrees with these
comments and haa redefmed the data
requirements to reflect the performance
that can be achieved with one well-
maintained tMS. The fIDal requirements
are designed to elimina te 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 emiuion
limitations for sulfur dioxide and
nI trogen 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 a verages. for 24-hour periods.
and for the 30 successive boiler
operating days. These minimum
reqUIrements eliminate the need for
redundant CMS and mimmize the need
for testing uSing manual sampling
techniques. The mimmum requirements
app.\ separately to inlet and outlet
mo, oring systems.
1 . regulation allows calculation of
haul averages for the CMS using two
or mo e of the required four data points.
This provision was added to
,ccommodate those mOnItors for which
span and cahbration checks and minor
repairs might require more than 15
mmutes.
For any 24-hour period. emissIOns
data must be obtained for a minImum of
75 percent of the hours dunng which the
affected facility is opera ted (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
plulllled probe. or a s,oiled 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
pOllibility 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 t~e 30
successive boiler operating days. This
provision is based on EPA studies th!!t
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 wouki
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
Ihe data. The Administrator believes.
however. that a single properly
designed. mainlained. and operated
CMS with trained personnel and an
appropriate inveI1tory 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 ,i\uid a finding of
noncompliance witli the emission
standards solely by noncompliance with
the minImum data requirements.
Penalties related only to failure to meet
the minimum data requirements mav be
less than those for failure to meet the
emission standards and may no! provide
as great an Incentive to maintain
compliance with the regulations.
132
The procedure involves t~e .
calculation of standard devIations for
the available inlet SO. monitorinR dnta
and the available outlet SO. and NO,
monitoring data and assumes the da:a
are normally distributed. The standard
devia tion of the inlet monitoring da ta for
SO. 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 9S percent confidence
interval. The lower confidence limit of
the outlet emission rate is compared
with the allowable emission rate to
determine compliance. If the iower
confidence limit of the outlet emission
rate is greater than the allowable
emillion 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 thit
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 6O.11(d) to conti:1Ue
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 requirement.9
could allow the source owner to
circumvent the standard. since the
added procedure assumes random
variatiOiTS 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 opera ting parameters
during those perIods when emissions
data have not been obtained. This
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Federal Register I Vol. 44. No. 113 I Monday, June 11. 1979 I Rules and Regulations
33611
alternative was rejected because it
wculd 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 opera tors 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
FCD efficiency' ranging from 77.5 to 90
percent, with the scrubber operating at
an efficiency of 85 percent. The analysis
submitted by the commenter 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
ml!Bsured 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
monitormg requirements questioned the
need to respan the CMS for sulfur
dioxide when the sulfur content of the
fu.!1 changed by 0.5 percent. The intent
of this requirement was to assure that a
change in fuel sulfur content would not
re~ult 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 da ta.
Several comments were also received
cO,1cerning detailed technical items
contained in Performance Specifications
2 IInd 3, One comment. for example.
sUI!gested that a single "relative
accuracy" specification be used for the
en'ire CMS. as opposed to separate
va,ue~ for the pollutant and diluent
mer-Itors. Another comment questioned
th,> performance specification on
instrument reSDonse time. while still
otl:er commenis raised questions on
calibration procedures. EPA is in the
prncess 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 lie 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 commenters on this issue
supported the fuel pretreatment
crediting procedures 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 fmal regulation and
was also allowed under the proposal in
the optional "as-fll'ed" fuel sampling
procedures under'the SO. emission
monitoring requirements. By monitoring
SO. emissions (ng/I. Ib/million Btu) with
BIl..as-fll'ed fuel sampling system located
upstream of coal pulverizers and with
an in-stack continuous SO. monitoring
system downstream of the FCD system.
sulfur removal credits are combined for
the coal pulverizer, bottom ash. fly ash
and FCD 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
refm2d fuel oil. The Administrator
intended to allow fuel pretreatment
credi ts for all fuel oil desulfuriza tion
processes used in preparation of utility
boiler fuels. Thus, the input and output
from oil desulfurization processes (e.g..
hydro treatment 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
deBulfurizer 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 bourid to the
heavier residual oils which may have a
sulfur content of twice the input crude
oil. The residual oils can be upgraded to
133
a lower sulfur utility steam generator
fuel through the use of desulfurizal10n
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 used to
determine oil pretreatment credits and
not the lower sulfur refinery input crude.
This procedure will allow full credit for
residual oil hydrodesulfurization umts.
In relation to fuel pretreatment credits
for coal. commenters requested that
sampling be allowed prior to the imtial
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 ngl! (Ib/
million Btu) and any removal of rock or
other similar reject material will not
change the potential SO. emission rate
(ng/I; lb/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
SO. removal credit for pretreatment
equipment.
Miscellaneous
Establishment of standards of
performl!nce for electric utility steam
generating units was preceded by the
Administrator's determination that these
~ources contribute significantly to air
pollution which causes or contributes to
the endangerment of public he£lth or
welfare (36 FR 5931). and by proposal of
regulations on September 19,1978 :43 FR
42154}, In addition. a preproposaJ public
hearing (May 25-26, 1977) and a
postproposal public hearing (December
12-13, 1978) was held after notifiea tlOn
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 exper!s. and
Federal departments and agencies.
Standards of performance for new
fossil-fuel-fired stationary sources
established under sechon 111 of the
Clean Air Act reflect:
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eel I R . t I Vol 44 No 113 I Monday, June 11, 1979 I Rules and Regulations
F era egIser .,.
Application cr the be.t tecbnol08ic~1
,ystem or continuous emiulon reduction
which (takins inlo con.ideration the cost of
achlevlnS .uch emillion reduction. any
nonalf quahty health and environmental
impact and enersy requirement.) the
Adm111i.tralor determinee haa been
adequately demon.trated. [.ection 111(a)(1))
Although there may be emillion
control technology available that can
reduce emissions below those levels
required to comply with slanda~ds of
performance. this technology rmght not
be selected as the basis of standards of
performance due to costs allociated
With its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable eOUSSlon
control. In fact. the Act requires (or has
potenhal for requiring] the impositi~n of
a more stringent emission standard ID
several .ituations.
For example. applicable costs do not
playas prominent a role in detennin~g
the "lowest achievable eIDJ1810n rate
for new or modiCied sources located in
non a Itainment areu. i.e., those areas
where statutorily-mandated health and
welfare standard. are being violated. In
this respect. section 173 of the Act
requires tha t a new or modiCied louree
constructed in an araa that exceedl 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 deCines 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
such class or category of source, unless
the owner or operator of the proposed
source demonstrates that such
limitahons are not achievable. or
(81 The most stringent emission
limitation which is achieved in practice
by such class or ca tegory of source.
whichever is more stringent.
In "0 event can the emission rate
excped any applicable new source
performance standard [section 171(3)).
A similar sltuahon may arise under
the prevention of signiCicant
deten "ra tion of air quali ty provisions of
the A, ' (Part C). These provisions
requI; 'hat certain sources [referred to
m sect n 169(1)) employ "best available
control ~chnology" [as deCined in
sectIOn 169(3)] for all pollutants
regulated under the Act. Best available
controi technology (BACT] must be
detprmmed on a c..se-by-case basis.
t~l..ln~ energy. em Ironmental and
econc1Cl11C Impacts. and other costs inlo
dccnunt. In no event may the application
oi 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 wellare. For thi.
purpose, SIP's must in some cases
require gI'ea ter emi.sion reductions than
those required by standard. of
performance for new sources.
Finally, State. are free under .ection
116 of the Act to establi.h even more
stringent emission limits than those
established under section 111 or those
neceuary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some case. be
.ubject to limitations more stringent
than EPA'. standards of performance
under section 111, and pro.pective
owners and operators of new sources
should be aware of thi. possibility in
planning for .uch facilities.
Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirement. in this
regulation will automatically expire five
years from the date of promulgation
unle.. 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
require. the Administrator to prepare an
economic impact assessment ~or
revisions determined by the
Administrator to be .ubstantial. The
Admini.trator has determined that the..
revisions are sub.tantial and ha.
prepared an economic impact
assessment and included the required
information in the background
information documents.
Daled: Juna 1, 1979.
DouaJas M. Coalle.
Admim$trotor.
PART 6O-STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
In 40 CFR Part 60. t 60.6 of Subpart A
is revised. the heading and I 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 6O.6(d) and t 6O.8(f) are
revised as follows:
160.8 P8t1ormance te.t..
134
(d) The owner or operat~r o( m
affected facility shall provIde n.e
Administrator at least 30 day. prior
notice of any perforriJance test, except
as specified under other subparts, to .
afford the Administrator the opportumty
to have an observer present.
(f) UnJes. otherwise .pecified in the
applicable subpart, each performance
test .hall 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
mean. of results of the three runs shall
apply. In the event that a sample is
accidentally lo.t or conditions occur in
which one of the three runs must be
discontinued because of forced
.hutdown, failure of an irreplaceable
portion of the sample train, extreme
meteorological conditions, or other
circumstance., beyond the owner or
operator'. 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-Standard. ot Performance
tor Fo..II-FueI-Flred Steam Generator.
tor Which Con.tructlon I. Commenced
After Augu.t 17, 1971
3. Section 60.40 is amended by adding
paragraph (d) a. follow.:
180.40 Applicability and d88lgnatlon of
affected facility.
(d) Any facility covered under Subpart
Da i. not covered under This Subpart.
(See. 111. 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411, 7601(a)).)
4. A new Subpart Da i. added as
follows:
Subpart D-Standard. of Performance for
Electric Utility Steam Gener.tlng Units for
Which Con.tructlon I. Commenced After
September 18,1978
See.
8O.40a Applicsbility and designation of
affected facility.
8O.41a Definitions.
8O.42a Standard for particulate malter.
8O.43a Standard for sulfur dioxide.
8O.44a Standard for ni trogen oxides.
8O.45a Commercial demonstration permit.
8O.46a Compliance provisions.
8O.47a Emi.slon monitoring.
8O.48a Compliance determination
procedures and methods.
6O.49a Reporting requirements.
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Federal Register / Vol. 44, No..113 / Monday, June 11, 1979 / Rules and Regulations
336 )]
Authority: Sec. 111. 301(a) of the Clean Air
Act a. amended (42 U.S.C. 7411. 7601(a)), and
addItional authority 81 noted below.
Subpart Da-Standard. of
Performance for Electric UUUty Steam
Generating Unit. for Which
Con.tructlon I. Commenced After
September 18, 1978
f 80.408 Applicability 8nd d..lgn8Uon of
affected fRIlIty.
(a) The affected facility to which this
subpart applies is each electric utility
.team 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 fo~sil 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 ce.)
(I:) Any change to an existing fossil-
fuel-ftred steam generating unit to
acoommodate the use of combustible
ma terials, 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 fOlSil fuels, to
accommodate the use of any other fuel
(fossil or nonfossil) shall not bring that
unit under the applicability of this
subpart.
f 80.418 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 used for
com busting 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 such
ma terial for the purpose of crea ting
useful heat.
"Subbitwninous coal" means coal that
Is classified as subbituminous 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
Material.' (ASTM) Standard
Specification for Classification of Coals
by Rank D388-66.
"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 emilSlons (ng/J.
Ib/mi1l10n 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 nglJ (7.0 Ib/million Btu) heat
input for .olid fuel; and
(2) 75 ng/J (0.17 Ib/million Btu) heat
input for liquid fuels.
(b) For sulfur dioxide is determined
under 180.48a(b).
(c) For nitrogen oxides is:
(1) 290'nglJ (0.67 Ib/millipn Btu) heat.
Input for gaseous fuels:
(2) 310 nglJ (0.72Ib/million Btu) heat
input for liquid fuels; and
(3) 990 ng/J (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 by 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
fargest 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
135
with one or more electric power
interconnections to the principal
company and which have
geographically adjoining service areas.
"Net system capacity" means the sum
of the net electric generating capablltty
(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
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) plus firm contractual
purchases tha t are in terconnected to the
affected facility that has the
malfunctioning flue gas desulfurization
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
owner. hip 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 sE-rvice area interconnected
with the affected facility that has the
malfunctioning flue gas desulfuriza tion
system plus firm contractual sales to
other electric utility companies. Sales to
other electric utility companies (e.g.,
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 general1ng
units, internal combustion engines. gas
turbines, nuclear units. hydroelectric
units, and all other electric genera ting
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 contractudl
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 capabdity
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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33614
Federal Register I Vol. 44. No. 113 I Monday, June 11, 1979 I Rules and Regulations
additional load, The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output i.
otherwise established by contractual
arrangement.
"Available purchase power" meBJ\J
the leuer 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 device.
between the principal company and all
neighboring companies. minu. the sum
of the electric power load on these
interconnection..
(c) The rated capacity of the power
transmiuion line. between the power
interconnection device. and the electric
generating units (the unit in the principal
company that ha. the malfunctioning
flue Ras desulfurization system and the
unit(s) in the neighboring company
supplYing replacement electrical power)
less the electric power load on the. I'
tran.mission lines.
"Spare flue g88 de.u1furization .ystem
module" mean. a separate system of
sulfur dioxide emiuion control
equipment capable of treating an
amount of flue g88 equal to the total
amount of flue gll8 generated by an
affected facility when operated at
maximum capacity divided by the total
number of nonspare flue gas
desulfurization module. in the system.
"Emel'1lency 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 pnncipal company interconnected
with the affected facility is being
operated. and
(21 All available purchase power
interconnected with the affected facility
is being obtained. or
(bJ The electric generation demand is
belnlo: shifted as qUickly as possible from
an affected facility with a
malfunctionmg flue gas desulfurization
sys! en to one or more electrical
gen, . !ting units held in reserve by the
pm: 'al company or by a neighboring
com I- ny, or
. (cl, n affected facility with a
maJfunclioning flue gas desulfurization
system becomes the only available unit
to mamtain a part or all of the principal
company's system emergency reserves
and the unit is operated in spinning
r~serve at the lowest practical electric
genera lion load consistent with not
caus;ng signIficant physical damage to
the unit. U the unit i. operated at a
higher load to meet load demand. an
emel'1lency condition would not exist
unles. the conditioDl under (a) of thi.
definition apply.
"Electric utility combIned cycle ga.
turbine" means any combined cycle gas
turbine u.ed for electric generation that
i. constructed for the purpose of
.upplying more than one-third of It.
potential electric output capacity and
more than Z5 MW electrical output to
any utility power di.tributioD .ystem for
.ale. Any .team di.tribution sy.tem that
I. constructed for the purpose of
providing steam to a .team electric
generator that would produce electrical
power for .ale i. also con.idered in
determining the electrical energy output
capacity of the &Hected facilltJ.
"Potential electrical output capacity"
I. dermed as 33 percent of the maximum
design heat input cepacity of the .team
generating unit (e.g.. a steam generaUDI
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 gal turbines the
potential electrical output capacity is
determined on the be.i. of the fo.sil-fuel
firing capacity of the steam generator
exclusive of the heat Input and electrical
power contribution by the gal turbine.
"Anthracite" means coal that is
classified 88 anthracite according to the
American Society of Te'liD8 and
Meterials' (ASTM) Standard
Specification for Classification of Coals
by Rank D381H16.
"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,
.olvent refined coal. liquified coaL arid
gaaified coal.
":U-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
Stale of Hawaii. the Virgin Island.,
Guam, American Samoa, the
Commonwealth of Puerto Rico. or the
Northern Mariana Islands.
"Boiler operating day" iDeans a 24-
hour period during which fossil fuel is
combusted in a steam generating unit for
the entire 24 houra.
110.428 Standard for particulate matter.
(a) On and after the da(e on which the
performance test required to be
conducted under I 60.8 is completed. no
owner or operator subject to the
136
provision. 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/) (0.03 Ib/million Btu) heat
input derived from the combultion of
.olid. liquid. or gaseous fuel;
(2) 1 percent of the potential
combultion concentration (99 percent
reduction) when combusting solid fuel;
and
(3) 30 percent of potential combustion
concentration (70 percent reduction)
when combusting liquid fuel.
(b) On and after the date the
particulate matter performance test
required to be conducted under I 60.8 is
completed. no owner or operator subject
to the provisions of this subpart shall
, cause to be discharged into the
a tmosphere 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.
110.438 Standard for 8IIIfur dIoldde.
(a) On and after the date on which the
initial performance telt required to be
conducted under I 60.8 is cQmpleted, no
owner or operator subject to the
provilion. of this subpart shall cause to
be discharged into the atmo.phere from
any affected facility which combusts
solid fuel or .olid-derived fuel. except as
provided under paragraphs (c). (d), (f) or
(h) of this section. any gase. which
contain sulfur dioxide in excess of:
(1) 520 ng/) (1.20 Iblmillion 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/) (0.60 lb/million Btu) heat input.
(b) On and after the date on which the
initial performance test required to be
conducted under I 60.8 is completed. no
owner or operator subject to the
provisions of this subpart shall ca use to
be discharged into the atmosphere from
any affected facility which com busts
liquid or gaseous fuels (except for liquid
or gaseou. fuels derived from solid f\:els
and as provided under paragraphs (e) or
(h) of this section). any gases which
contain sulfur dioxide in excess of:
(1) 340 ng/) (0.60 lb/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 100 percent of the potential
combu,stion concentration (zero percf'nt
reduchon) when emissions are less than
86 ng/) (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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33615
co,ducted under ~ 60.8 is complete. no
owner or operator subject to the
provisions of this subpart shall cause to
bl! discharged into the atmosphere frum
any affected facili!y which com busts
solid solvent refined coal (SRC-I) any
ga5es which contain sulfur dioxide in
excess of 520 ng/l (1.20 lb/million Btu)
heat input and 15 percent of the
potential combustion concentration (1'15
percent reduction) except as provided
under paragraph (f) of this section;
compliance with the emission limitation
is determined on a 3D-day rolling
average basis and compliance with the
percent reduction requirement is
determined on a 24-hour basis.
id) Sulfur dioxide emissions are
limited to 520 ng/l (1.20 lb/million Btu)
heat input from any affected facility
which:
(1) Combusts 100 percent anthracite.
(2) Is classified as a resource recovery
facility. or
13) Is located in a non continental area
and com busts solid fuel or solid-derived
fuel.
Ie) Sulfur dixoide emissions are
limited to 340 nglJ (0.80 lb/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 ~ 6O.45a.
(g) Compliance with the emission
limitation and percent reduction
requirements under this section are both
determined on a 3D-day rolling average
ba8is 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/l
(0.00 lb/million Btu) heat input
Eso, = (340 x + 520 YJ/100 and
Pso, = to percent
(2) II emissions of sulfur dioxide to the
atmosphere are equal to or less than 260
ngil (O.60.lb/million Btu] heat input:
Em. = (340 x + 520 y]/too and
pso. = {90 x + 70 y]/1oo
where:
E.o. is the prorated sulfur dioxide emission
limIt (ng/) heat input).
pso. is the percentage of pOlential sulfur
dioxide emission allowed (percent
reduchon required = too-Pso,).
x is the percenlage of lolal heal inpul derived
from Ihe cOl!1bu.tiO!1 of liquid or gaseous
fuels [excludmg solid-derived fuels)
y is the percenl1lge of 1;,lal heat inpul derived
from Ihe combustion of solid fuel
(including solid-derived fuels)
t &0.44. Standard tor 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 secUon. any
gases which contain nitrogen oxides in
excess of the following emission limits,
based on a 3D-day rolling average.
(1) NO. Emission Limits-
FuoI \';1>0
e_-
"VI J (1b/moilion alu)
hel' Input
~F-
~ fuoII -.....--.....
All .- 1uoI1..........-...-.....-
Uquod FuoIc
~1uoII._.........._.-
SMI8 ""...............-...................
All .- 1uoII-......_.--.-
Solid FuoI8:
~ fuoI8 ......................
Anot IuoI ~ more IIIIn
25%. by -.gm. 0081'- - Enml>lfIom NO,
.- - NO,
..-..nng
--
2'0
88
210
2'0
130
210
A"Y IuoI ~ mooelhan
25'110. by woigIII. Ngnrtl , the
rtgrit8 i8 "*-d WI Nontt
DI"'18, SouIII DoIIoI8, at
----
WI I 8I8g flip -...........-
~ noIlUI>joct 10 the 340
ngtJ -. onput- limit
s- 0081........_..-:.
al..-...,. 0081__._....-...-
AnIlvICi18 COllI..........................
All - fuoII...........................
340 (0.80)
280 (060)
2'0 (0.50)
280 (080)
280 (0.80)
280 (0.60)
(2) NO. reduction requirements-
FuoI \';1>0
- r8CM:tIan
01 pot.....
c:omI>u8-
--
G_-...--.-..---..
lJquod fuoII.....___.-..-...--
Solid IuoIa "'-"---""-""''''''-''''
(bJ 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 L;e
Administrator in accordance with the
provisions of A 6O.45a.
(c) When two or more fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
END. ={86 w+130 x+Z10 y+260 z]/1oo
137
(0.50)
(0.20)
(0.501
(0.50)
(0.30)
where:
E.o is the applicable stanC;Jrd for nll.['~,'~
. . oxides when multiple fuels are
comb us led simultane;,usly [ng/) heat
input);
w is t!,e percentage of total heat inp'jt
deMved frol:1 the combustion of b.ls
subject to the 86 ng/! heat input
standard:
x is the percentJge of tolal heat input dem'ed
from the cOIT'~ustion of fue!q subject to
the 130 n~.iJ !:eAt :nput slandard;
y is the per~entage of lolal heat in~ut de"v~d
from the com;)~stion of fuels subject to
the 210 r.g/! ':031 input standard: u:,d
Z is the percen:~,e of t
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33616
Federal Repter I Vol. 44. No. 113 I Monday, June 11. 1979 I Rules and Regulations
heat input on a 3G-day rollins average
basil.
(e) Commercial demonltration. permita
may not exceed the following equivalent
MW electrica1generation capacity for
anyone technology category. and the
total equivalent MW electrical
generation capacity for all commercial
demonstration plantl may not exceed
15.000 MW.
T~
E-
-
-
(IotW -
-
--
Sold - - COlI
ISAC q.... ............ _.._-
~--
1'_1...-.....-...-.-
~--
11>'-..----
CooI_....___-
so, 8.lIOII-10.00II
so,
so,
NO.
<00-3.00II
400-1.200
750-'0.00II
T_-tor..
-.--.--
f 60."'. Compu- provIaIona.
(a) Compliance with the particulate
matter emillion limitation under
1 6O.428(a)(1) conltitutel compliance
with the percent reduction requirementa
for particulate matter under
1 6O.42a(a)(2) and (3).
(b) Compliance with the nitrogen
oxidel emillion limitation under
1 6O.44a(a) conltitutel compliance with
the percent reduction requirementl
under 160.44a(a)(2).
(c) The particulate matter emillion
Itandardl under 1 6O.42a and the
nitrogen oxidel emillion Itandard.
under 1 6O.44a apply at all timel except
during periodl of Itartup, Ihutdown, or
malfunction. The lulfur dioxide emillion
.tandardl under I 6O.43a apply at .11
times except during periodl of Itartup.
shutdown, or when both emergency
conditions exilt and the procedurel
under paragraph (d) of \hillection are
implemented.
(d) During emergency conditionl in
the pnncipal company, an affected
facility with a malfunctioning flue'ga.
desulfurization system may be operated
if sulfur dioxide emissions are
minimIzed by:
(1) Operating all operable flue gas
dese' 'urization Iystem modules, and
brin 19 back into operation any
mallt ctioned module al soon al
repa Ir~ 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 anv sulfur dioxide emiuion nduction
or whIch would have suffered significant
physical damage if they had remained in
opera tion, and
11.000
(3) De.igning. con.tructlns. and
operatlns a .pare flua ga.
de.ulfurization .y.tem module for an
affected facility hlrpr than 385 MW
(1.250 mI1Uon 8tu/hr) heat Input
(approximately 125 MW electrical
output capacity). The Admini.trator
may at hi. di.cretion require the owner
or operator within tIO day. of
notification to demonstrate .pare
module capability. To demon.trate this
capability, tha ownar or operator mu.t
demon.trate compliance with the
appropriate requirement. under
paragraph (a). (b). (d). (e), and (i) under
I 1IO.43a for any period of operation
la.un, &om 24 hours to 30 day. wben:
(I) Anyone flue ga. de.ulfurization
module i. not operated.
(ii) The affected facility il operatlns at
the maximum beat Input rate,
(Iii) The fuel fired durins the 24-bour
to »-day period Is repre.entative of the
type and average .uIfur content of fuel
u.ed over a typical 3G-day period. and
(Iv) The owner or operator baa given
the Admini.trator at lea.t 30 'day. notice
of the date and period of time over
wbich the demonltration will be
performed.
(e) Alter the initial performanel telt
required under I 60.8, compliance with
the .ulfur dioxide emillion limitation.
and percentage reduction requirement.
under 160.43a and the'D.itrogen oxide.
emillion limitation. under 160.44a i.
baled on the average emillion rate for
30 .ucces.ive boiler operating day.. A
.eparate performance test il completed
at the end of each boiler operating day
after the initial performance telt. and a
new 30 day average emillion rate for
both .ulfur dioxide and nitrogen oxidel
and a new percent reduction for lulfur
dioxide are calculated to Ihow
compliance with the Itandards.
(f) For the initial performance telt
required under I 60.8, compliance with
the lulfur dioxide emission limitation.
and percent reduction requirementl
under I 6O.43a and the nitrogen oxide.
emiasion limitation under I 6O.44a is
based on the average emiliion ratel for
lulfur dioxide, nitrogen oxides. and
percent reduction for lulfur dioxide for
the fu.t 30 succeilive boiler operating
daYI. The initial performance telt is the
only test in which at lea~1 30 daYI prior
notice is required unlesl otherwile
.pecified by the Administrator. The
initial performance test i. to be
Icheduled so tha t the first boiler
operating day of the 30 succellive boiler
operating daYI il completed within 60 -
days after achieving the maximum
production rate at which the affected
facility will be operated. but not later
138
than 1110 day. after initial .tartup of the
facility.
(g) Compliance il determined by
calculating the arithmetic average of all
hourly emi18ion rate. for SO. and NO.
for the 30 lucce..ive boiler operating
day.. except for data obtained during
atartup. Ihutdown, malfunction (NO.
only). or emergency condition. (SO.
only). Compliance with the percentage
reduction requirement for 80. i.
determined ba.ed on the average inlet
and average outlet SO. emillion rate.
for the 30 luccellive boiler operating
day..
(h) If an owner or operator has not
obtained the minimum quantity of
emillion data a. required under I 6O.47a
of this lubpart. compliance of the
affected facility with the emi..ion
requlrementa under II 1IO.43a and 6O.44a
of thll .ubpart for the day on which the
3O-day period end. may be determined
by the Admini.trator by following Ihe
applicable procedurel in sections 6.0
and 7.0 of Reference Method 19
(Appendix A).
I 1O.47a Emla8lon monitoring.
(a) Tbe owner or operator of an
affected facility .hall in.tall. cali~rate.
maintain. and operate a continuoul
monitoring Iystem. and record the
output of the 'Yltem. for measuring the
opacity of emillioni dilcharged to the
atmolphere. except where galeous fuel
I. the oniy fuel combulted. If opacity
Interference due to water droplet. exists
in the Itack (for example, from the use
of an FGD Iy.tem). the opacity i.
monitored upltream of the Interference
(at the inlet to the FGD Iy.tem). If
opacity interference Is experienced at
all location. (both at the inlet and outlet
of the lulfur dioxide controlIYltem).
alternate parameters indicative of the
particulate matter control sy.tem's
performance are monitored (.ubject 10
the approval of the Administrator).
(b) The owner or operator of an
affected facility shall inltall. calibrate,
maintain. and operate a continuous
monitoring system, and record the
output of the sYltem, for mea.uring
.ulfur dioxide emis.ion., except where
natural gas is the only fuel combusted.
a. Callow.:
(1) Sulfur dioxide emissions are
monitored at both the inlet and outlet of
the lulfur dioxide control device. .
(2) For a facility which qualifles under
the provi.ion. of I 6O.43a(d). sulfur
dioxide emi.lionl are only monitored as
dilcharged to the atmolphere.
(3) An "as fired" fuel monitonng
system (upstream of coal pulverizerl)
meeting the requirements of Method 19
(Appendix A) may be used to determine
-------
Federal Register I Vol. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
33617
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)(1) of this section.
(e) 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 me.asuring
nitrogen oxides emissions discharged to
the atmosphera.
(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) Tbe 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.
(I') 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 uescribed in paragraph (hI 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 IOO.13(h) are
expressed in nglI (Ibs/million Btu) heat
input and used to calculate the average
emission rates under 160.46a. The 1-
hour averages are calculated using the
data points required under I 5O.13(b). At
lea8t two data points must be used to
calculate the 1-hour averages.
(h) Reference methods used to
sup;Jlement continuous monitoring
s}'s~pm data to meet the minimum data
reqldre:uents in paragraph I 6O.47a(1')
WI1\ be used as specified below or
otl:l'rwise approved by the
Administrator.
(1) Reference Methods 3. 6. and 7. as
applicable. are used. The sampling
location(s) are the same as those usad
f\Jr the continuous monitorill8 system.
(21 For Method 6. the minimum
sampling time is ;:Q minutas and the
minimum sampling volume is 0.02 dscm
(0';1 dscl') for each sample. Samples are
laken at approximately 50-minute
intervals. Each sample represents a 1-
hour average.
(3) For Method 7. samples are taken at
approximately 3G-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
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/I (Ib/million
Btu) heat input are detennined 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
160.13(c) and calibration checks under
IOO.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 60
percent and for a continuous monitoring
system measuring nitrogen oxides is
detennined as follows:
F_"'"
Spon .- far
""'oven 0- (ppml
108. ..........-.....-..-------...... .-......
UquId ......-........---.--.--.....-....-.....
SoIod.........._---...---.--........--.-
ComIIOnatlon....__................-...........-
500
500
1.000
500 I.. VI + 1.000z
where:
x IS the fraction of total heat input derived
from gaseous f08s11 fuel.
y is the fraction of totat heat input derived
from liquid fossil fuel. and
z 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
ronndad to tha 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
139
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 ,1i
maximum estimated hourly potential
emissions of the fuel fired.
(Sec. 114. Clean Air Act as amended (42
U.S.C. 7414).)
o 60.488 Compliance determination
procedurea and methodL
(a) The following procedures and
reference methods are used to determine
compliance with the standards for
particulate matter under I 6O.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 d8cm (60 dscf) except that
smaller sampling times or volumes.
when necessitatad 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 samp1in~
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/) heat
input is determined using the oxygen or
carbon-dioxide measurements and
particulate matter measurements
obtained under this section. the dry
basis F,.factor and the dry basis
emission rate calculation procedure
contained in Method 19 (Appendix .\)
(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 j:r1cr
to a wet flue gas desulfurization sys!em.
(h) The following procedures and
methods are used 10 determine
compliance with the sulfur dioxide
standards under I 6O.0I3a.
(1) Determine the percent of potent1~1
combustion concentration (percent PCC)
emitted to the atmosphere as follows.
-------
33618
Federal Register I Vol. 44, No. 113 I Monday, June 11, 1979 I Rules and Regulations
(i) Fuel Pretreatment ('I(, R,):
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 c.ptional. For purposes of
determining compliance with any
percent reduction requirements under
I 6O.43a. any reduction in potential SO.
emissions resulting from the following
processes may be credited:
(A) Fuel pretreatment (physical coal
cleaning. hydrodesulfurization of fuel
011. etc.).
[B) Coal pulverizers. and
(C) Bottom and flyash interactions.
(ii) Sulfur Dioxide Control System ('I(,
R.): 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
mom tor 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 ('I(, 11.):
Determine the overall percent reduction
using the results obtained in paragraphs
(b)(1) (i) and (ii) of this section following
the procedures in Method 19 (Appendix
AJ. 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 penod in the
current quarter.
(i") Percent emitted (B. PCC):
Calculate the percent of potential
combustion concentration emitted to the
atm.'n: Percent PCC= 1oo-Percent R..
(2, )etermine the sulfur dioxide
eml~SI >n rates following the procedures
In Met.lod 19 (Appendix A).
(c] The procedures and methods
outhned in Method 19 (Appendix A) are
u~ed in conjunction with the 30-day
nltr(1~en.oxides emission data collected
under ~ 6O.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 u.1ng the procedures of
Method 19 (Appendix A). The sulfur
dioxide and nitrogen oxide. emission
rates from the gas turbine used in
Method 19 (Appendix A) calculations
are determined wherr- the gas turbine i.
performance tested under subpart GG.
The potential uncontrolled particulate
matter emillion rate from a sas turbine
I. defined as 17 nglI (0.04 Ib/million Btu)
heat input.
, 1O.41a Reporting requlr8menta.
(a) For sulfur dioxide, nitrogen oxides,
and particulate matter emissions, the
performance te.t data from the Initial
performance te.t and from the
performance evaluation of the
contin!1ous monitor. (lncludina the
transmissometer) are submitted to the
Admini.trator.
(b) For sulfur dioxide and nitrogen
oxide. the following information is
reponed to the Administrator for each
24-hour period.
(1) Calendar date.
(2) The average sulfur dioxide and
nitrogen oxide emission rates (nglJ 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
emillion 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) Idenhfication 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 (SO. 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.
140
(81 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 abili ty of the con tinuous
monitoring system to comply with
Performance Specification. 2 or 3.
(c) If the minimum quantity of
emission data as required by I 6O.47a is
not obtained for any 30 successive
boiler operating days, the following
information obtained under the
requirements of I 6O.46a(h) is reporlt!d
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 ra tes (s.)
and inlet emission rates (s,) as
applicable.
(3) The lower confidence limit for the
mean outlet emission rate (E.;) and the
upper confidence limit for the mean IDlet
emillion rate (Et") as applicable.
(4) The applicable potential
combustion concentration.
(5) The ratio of the upper confidence
limit for the mean outlet emission rate
(E,,") and the allowable emission rale
(Eo..) 81 applicable.
(d) If any standards under I 60.43<1 are
exce,eded during emergency conditions
because of control system malfunction,
the owner or operator of the affected
facility shall submit a signed sta tement:
(1) Indica ting if emergency conditIOns
existed and requirements under
I 6O.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 'In
the ownet or opera.tor's electric utility
system and the affected facility;
(iii) Amount of power purchased f~om
interconnected neighboring utility
co~panies during the emergency pe:'iod;
(IV) Percent reduction in emissions
achieved:
(v) Atmospheric emission rate (ngm
of the pollutant discharged; and
(vi) Actions taken 10 correct control
system malfunction. -
(e) If fuel pretreatment credit toward
the sulfur dioxide emission standard
under I 6O.43a is claimed. the owner or
operator of the affected facIlity shal]
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
-------
Federal Register I Vol. 44, No. 113 I Monday, June 11, 1979 I Rules and Regulations
33619
provisions of ~ 6O.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 pret1'eatment 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 avsilable, 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 .hall submit a signed
statement indicating whether:
(1) The required continuous
monitoring system calibration, span, and
dr:ft checks or other periodic audits
have or have not been performed as
specified.
;2) The data used to show compliance
wus 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.
(4) Compliance with the standards has
or has not been achieved during the
reporting period.
[hI 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
st!tndards under ~ 6O.42a(b). Opacity
. - le,'els in excess of the applicable
opllcity standard and the date of such
ex~esses are to be submitted to the
Administrator each calendar quarter.
Ii) The owner or operator of an
affected facilr!y shall submit the written
reports required under this section and
subpart A to the Administrator for every
calendar quarter. All quarterly reports
shull be postmarked by the 30th day
fol:owing the end of each calendar
quarter.
(Sec. 114. Clean Air Act as amended (42
U.S.C. 7U4j.)
4. Appendix A to part 60 is amended
by adding new reference Method 19 as
follows:
Appendix A-Reference Methods
Method 19. Determinatian of Sulfur
DioJtide Removal Efficiency and
Particulate. Sulfur Dioxide and Nitrogen
Oxides Emission Rates From Electric
Utility Steam Generotors
1. Principle and Applicability
1.1 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 [nglJoule, lb/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 calcula te
particulate, sulfur dioxide. and nitrogen
oxides emission rates. F factors are
values relating combustion gas volume
to the heat conteJlt 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
I Use the mOlt recent revilion or designation of
the ASTM procedW'tl opecified
141
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 fer
each product coal lot.
2.1.2 ASTM Lot Size. For the purpose
of Section 2.1.1. the product coallo! 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 cOni
lot. Typically, the lot size is the weight
of coal processsed in a 1-day (24 hours)
period. If more than one type of cOni 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 9O-day quarterly
fuel quantity for a specific power plant
may be used if representative sampling
can be conducted for the raw coal dnd
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 I for
sample preparation, ASTM D 3177 I for
sulfur analysis, and ASTM D 3173 ' for
moisture analysis. Use ASTM D 3176 I
for gross calonfic value determination.
2.2 Liquid Fossil Fuel.
2.2.1 Sample Collection. Use AST~
D 270 I following the practices outlined
for continuous sampling for each gross
sample representing each fuello!.
2.2.2 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 fuello!. The weight of each
crude liquid fuel t~'pe used to produce
one product fuel lot is defined as one
inlet fuel lot.
NoI8.- AJternate defir.ltlons of fI:cllot
sizes may be specIfied subject to r-r,ur
approval of the Administrator.
Not8.- For the purposes of th,s method.
raw or Inlet fuel (coal or 011) is defined dS the
fuel delivered to the desulfurization
pretreatment facility or to the steam
generating plant. For pretreated oil the mput
oil to the oil desulfuriza tion process (I' g.
hydro treatment emitted) is sampled.
2.2.3 Sample Analysis. Determine
the percent sulfur content (%S) and
gross calonfic value (GCV). Use AST~fD
240 I for the sample analysis. This "tllle
can be assumed to be on a dry oasIs.
I Use the most recent reVISion or de~l1gna!lon of
the ASTM procedure opecllied
-------
336211
Federal Register I Vol. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
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:
:Rf
100 [1
lSo/GCV 0]
ISf/GCVf
Where:
"(,R,= Sulfur dioxide removal efficiency due
pretreetment; percenL
'JI.S. = Sulfur content of the product fuel lot on
a dry beei.; weight PercenL
"(,5, = Sulfur content of the inlet fuel lot on a
dry bui.; weight percenL
GCV. a Gro.. calorific value for the outlet
fuel lot on a drJ-ba.i.; kJlkg (Btu/lb).
GCV,- Gro.. calorific value for the inlet fuel
lot on a dry ba.i.; kJlkg (Btu/tb).
Nota~U more than one fuel type ia used to
produce the product fuel. uae the following
equation to calculate the .ulfur contenta per
umt of heat content of the total fuello\, 'reS/
GCV:
:S/GCV
n
t
k.l
Yk(ISk/GCVk)
Where;
Y. = The fraction of total mall input derived
from each type. k. of fuel.
"s,,-Sulfur content of each fuel type. k. on a
dry ba.i.; weight percenL
GCV. - Groaa calorific valua for each fuel
type. k. on a dry beei.; kJlkg (Btu/lb).
n a The number of different type. of fuel..
3. Detennination of Sulfur Removal
Efficiency of the Sulfur Dioxide Control
De~'/ce
3.1 Sampling. ~etermine 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
5. The inlet sulfur dioxide emi88ion rate
may be determined through fuel analysis
(Optional. see Section 3.3.)
3.:. CalculatIon. Calculate the
perr~nt removal efficiency using the
follt1wing equation;
~R . I 00 x
~(m)
E
S02°
!SOl)
2
(1.0 -
Where:
'JI.1t" - Sulfur dioxide removal efficiency of
the sulfur dioxide control.y.tem using
inlet and outlet monitoring data; percenL
E.o .=SuIfur dioxide eml88ion rate from the
outlet of the .uIfur dioxide control
.y.tem; ng/I (Ib/million BIu).
E.o ,. Sulfur dioxide emilsion rate 10 the
outlet of the lulfur dioxide control
IYltem; ng/I (lb/million BIu).
3.3 As-fired Fuel Analysis (Optional
Procedure). H 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 throush an as-
fired fuel analysis In lieu of data from a
sulfur dioxide control system inlet gas
monitor. fuel samples must bit 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 I 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 sulfw content and
gross calorific value. The ASTM
procedures for determining sulfur
content are defined in Ihe applicable
paragraphs of Section Z.
3.3.2 Calculation of Sulfur DioxIde
Input Rate. The suHur dioxide imput rate
determined from fuel analysis is
calculated by:
Is 2.0(lSf) x 107 for S. 1. unfts.
6CY
Is 2.0(15,1 x 10. for Englfsh unfts.
GCY
Where:
Is
. Sulfur dfoxfde fnput rite from as-ffred fue1 analysfs,
ng/J (lb/mf11fon Btu).
ISf. Su1fur content 0' as-ffred fuel. on a dry basfs; wefght
percent.
GCV . Gross calorfffc value for as-ffred fue1, on a dry basfs;
kJ/kg (Btu!1b).
3.3.3 Calculation of Sulfur Dioxide
Emiuion Reduction Using As-fired Fuel
Analysis. The sulfur dioxide emission
reduction efficiency is calculated using
the sulfur imput rate from paragraph
IR 9 ( f)
ESO
2
(1.0 - -r:-)
s
. 100 x
Where:
3.3.2 and the sulfur dioxide emission
rate. Eaot. determined in the-applicable
paragraph of Section 5.3. The equallon
for sulfur dioxide emission reduction
efficiency is:
:Rg(f) . Sulfur dfoxfde removal efffcfency of the sulfur
dfoxfde control system using as-fired fuel analysis
da ta; percent.
ESO . Sulfur dfoxfde emission rate from sulfur dfoxfde control
2
Is
system; ng/J (lb/millfon Stu).
. Sulfur dfoxfde fnput rate from as-ffred fuel analysis;
"g/J (lb/million Stu).
142
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Federal Register I Vol. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
33621
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 vawe. 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:
~RO
~R U
100(1.0 - (1.0 -~) (1.0 - ~)]
Where:
SRo . Overall sulfur dioxide reductioni percent.
SRf . Sulfur dioxide removal efficiency of fuel pretreatment
from Section 2: percent. Refer to applicable subpart
for definition of applicable averaging period.
SRg . Sulfur dioxide removal efficiency of sulfur dioxide control
device either 02 or C02 - based calculation or calculated
from fuel analysis and emission data, from Section 3:
percent.
Refer to applicable ~ubpart for definition of
applicable averaging peri~d.
5. Calculation of Particulate. Sulfur
Dioxide. and Nitrogen Oxides Emission
Rates
5.1 Sampling. Use the outlet SO. or
O. or CO. concentrations data obtained
in Section 3.1. Detennine the particulate.
NO., and O. or CO. concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Fbctor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2.). If combined fuels are
firl!d. the selected or calculated F factora
are prora ted 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
thl! fuel. A dry F factor (F oJ is the ra tio of
the volume of dry flue gases generated
to the calorific value of the fuel
cornbusted; a wet F factor (F,,) is the
ratio of the volume of wet flue gases
generated to the calorific value of the
fud combusted; and the carbon F factor
(F.] is the ratio of the volwne of carbon
dioxide generated 10 the calorific value
of the fuel combusted. When pollutant
For 51 Unl ts:
and oxygen concentrations have been
determined in Section 5.1. wet or drY F
factora are used. (F,,) factora and'
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbera: (Fe) or
(FoJ factors and associated emission
calculation procedures are used after
wet scrubbera.) When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1, F,
factora are used.
5.2.1 Average F Factors. Table 1
shows average Fd' F... and F, factors
(scm/'. sd/million Dtu) determined for
commonly used fuels. For fuels not
listed in Table 1. the F factora 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 da ta collection.
F 227.0(~H) + 95.7(~C) + 35.4(~S) + 8.6(~N) . 28.S(~0)
d . GCV
F .
w
347. 4( ~H)+95. 7( ~)+35. 4(:S )+8. 6(~N)-28. 5( sa )+13. O( \H20 )-
GCVw
F . 20.0(~)
c GCV
For Eng11sh Units:
F . 106[S.57(':H) + 1.53(O:C) + 0.57(~S) + 0.14(~N) - 0.~6(~O))
d GCV
106[5.57(:H)+1.53(':C)+O.57(:S)+O.14(':N)-0.46(':0)+O.21 (':H2 O)-J
GCV",
Fw
F
c
106[0.321(~C)]
. GCV
..The ~H20 term may be omitted If ~H and ':0 include ~he unaval1able
hydrogen and oxygen In the form of H20.
143
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33622
Federal Register I Vol. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
Where:
F.. F.. and F, have the unite of eemll. or eefl
mIllion Btu; '\H. ""C. ",,5. ""N. ",,0. and
'!.H.O are the concentrahons by weight
(e"pressed In percent) of hydrogen.
carbon. sulfur. mtrogen. oxygen. and
water from an ulhmate analyeie of the
luel; and GCV ie the gron calorific value
of the fuel in ~""g or Btu/lb and
consistent with the ultimate analyeie.
Follow ASTM D Z015' for eolid fuele. D
240' for liquid fuel.. and D 1826' for
gaaeou. fuel. 88 applicable in
determining GCV.
52.3 Combined Fuel Firing F Factor.
For affected facilities firing
combinations of f088i1 fuels or f088i1
fuels and wood residue. the F.. F.. or F.
factors determined by Sections 5.2.1 or
<;.2.2 of this section shall be prorated in
iccordance with applicable formula 88
"allows:
n
: t x k F dk or
d k-l
n
, t "It F wk or
w k-l
n
: "k F ck
c k-l
Where:
'. = The fraction of lotal heal Input derived
from each type of fuel. K.
n ~ The number of fuel. being burned in
comblnahon.
5.3 Calcula!ion of Emlss/on Rate.
Select from the following paragraphs the
applicable calculation procedure and
calculate the particulatl'. SO.. and NO.
emission rate. The valul's in the
equations are defined as
E=Pollutant emilllOn rate n~1) IIb/mllhon
Btu}.
C=Pollutant concentration. n~Jecm IIb/sct).
No'e.-It 'I necessary 10 ~ome casel 10
con\ ttrt measured concentratIOn units 10
olher units for thl'se calcula lions
Use the following table lor such
conversions;
Conv.,..on F ~,~ t0f'8 'or Concef'.,laon
---
r;,o""-
T')-
~un'Pf¥ by-
----
~/""'-
~''k-
b \C
00'"
~D"""
'0'" .
:~m. I"" J
"10 "'~
"9- !M;;1"'"
ng "-~
"9
-------
Federal Register I Vol. 44. No. 113 I Monday. June 11. 1979 I Rules and Regulations
33623
ESg
Ec - Xqt Eqt
Xsg
Where:
E.. ~ Pollutant emission rate £rom steam
generator effluent. ng/l.(lb/million Btu).
E'.,,=Pollutant emission rate In combined
cycle effluent: ng/l (lb/million Btu).
E.,=Pollutant emission rate £rom gas turbine
effluent; ng/l (Ib/million Btu).
x..=Prec!lon oltotal heat Input £rom
supplemental fuel fired to tha steam
genera t.or.
x.. = Fraction of total heat Input from gas
turbine exhaust gases.
Note.- The totel heat Input to the steam
generator is the sum of the heat Input from
supplemental fuel fU'1!d to the steam
generator and the heet input to the stesm
generator from the exhaust geses from the
gas turbine.
F.
Where:
s.=Standard deviation of the average outlet
hourly everage emission rates for the
reporting period: ng/l (Ib/million Btu).
a, = Standard deviation of the average inlet
hourly average emission rates for the
reporting period; ng/l (lb/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,,-t....a.
E. . = E. + to...a,
Where:
E" '= The lower confidence limit for the meAn
outlet emission rates; ng/l (lb/million
Btul.
E.' = The upper confidence limit for the mean
Inlel emission rate; ng/l (lb/million Blu).
t....= Values shown below for the indicated
number of available data points (n):
n V_Ior'- 10.
2 s~
3 2'2
4 235
5 2'3
S 2.02
7 1~
S 188
8 1~
10 1 B3
11 , S,
12.1S 1.17
17-21 173
22-28 1 71
V~1 Iro
32-51 , 68
52-81 , S7
82.151 , 56
152 at- 105
The values of this table are corrected for
n-l degrees of freedom. Use n equal to
the number of hourly average data
points.
7. Colculation to Demonstrate
Compliance When A vaJJable
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 (0{, R,) is
included in the overall reduction in
potential sulfur dioxide emissions ("Ii RoJ
and the "as-fired" fuel analysis is not
used. the potential combustion
concentration (PCC) is determined dS
follows:
EI* + 2 ~ - e~ 107; ng/J
~L~1 : 9
E * + 2 ~ 5, : si\ 104; lb/millian Btu.
1 ~VI - GC'Iy
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 directflring of
an auxiliary bumer into the exhaust gas.
The heat required for such bumers is
from 1 to 2 percent of total heat input of
the steam generating plant. The effect of
this fuel burning on the exhaust g88
components will be less than :tl.0
percent and will have a similar effect on
emission rate calculations. Because of
this small effect. a determination of
effluent g88 constituents from direct-
fired reheat bumers for correction of
stack-gas concentrations is not
necessary.
F.
T81118 11-1.-F Fsc:f0r8 for Vsrlou8 fIJeIs'
F.
FuoI type
d8cm
J
Cool:
Anthr1Cll8' .-.....--....-.....-
BUurnwtoua' ........-.............--
tlQt1l1.................................-...
CItJ', H"'__'''''...-.......-...,.-.-.--
Gu:
NIl_I....... "...,..........................
Propat'l8................................_-
e.n.n.....................--...........-
WOOd...............-........-.......-..-....
WOOd - "''''......'.............-..-.-
2.71)(10-'
2.83)( 10-'
2.8&>< 10-'
2.47 x 10-'
2.43 x 10-'
2.:M)(10'"
2." x 10-'
2.48><10-'
2.58)(10-'
-
10'8111
-
10'e..
oem
J
8cf
10'9tu
......
J
(10100)
(8780)
(8880)
(8190)
2.83 x 10-'
2.18)( 10-'
3.21 x 10-'
2.77)(10-'
(10540) 0.530)( 10-'
(106<0) 0._)(10-'
(119501 0.513>< 10-'
(103201 0.383)( 10-'
(18701
(18001
(1810)
(1-1
(HICO)
( 11110)
('250)
(1830)
(1850)
(8710) 2.S5)( 10"' (10810)
(S710) 2.74)( 10-' (10200)
(8710) 2.78)( 10-' (103110)
(8240) '---'.'-'- -.--.-
(Il8OO) ...--...-.. .-.-.-...-
0.287)( 10-'
0.321>< 10-'
0.337 x 10.'
0.492)( 10-'
0.487)( 10-'
. At - 8c:can1nO 1ItASn! 0.-
'CNde. r8l8du8l. Of .........
. 0.18mIt- 8' .- - 20" C (~. F) and 780 mm HII (28.92 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/J (Ib/million BtuJ for SO.
and NO. outlet data and. if applicable.
SO. inlet data using the following
equations:
. t Xo
Eo no
~
nl
EI
Where:
E,,:. Mean outlet emission rate; ng/l (lbl
million Btu).
E, =. Mean inlet emission rate; ng/l (Ib/million
Btu).
x" = Hourly average oullet emission rate; nglJ
(Ib/million Blu).
x,==Hourly average in let emission rate; ng/i
(Ib/million Btu).
Do ,'= 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 NO.
and. if applicable, the available inlet
hourly average emission rates for SO.
using the following equations:
So
. Q.; -' ~D e. (~:: ;0))
. (~-r;""\, fl' CE, - .J\
(. OJ - m) \.. ., - I )
'I
pee
pce
Where:
(i 51 ': 5~
~cVI - GEVJ .
Potential emissions r~cved by the pretrea~ent
process. using the fuel parame~ers defined in
section 2.3; ng/J (lb/mi1l1on etu).
145
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33624
Federal Register I Vol. 44. No. 113 I Monday, June 11. 1979 I Rules and Regulations
7.1.2 When the "as.fired" fuel
analysis is used and the removal
efficiency due to fuel pretrea Iment ('f. R,J
is not included in the overall reduction
in potential sulfur dioxide emissiona ('f.
R.J. the potential combustion
concentration (PeC) is determined as
fol!ows:
PCC=I"
Where:
r. = The sulfur dimdde input ra te as defiaed
in seetion 3.3
7.1.3 When the "as-fired" fuel
analysis i8 used and the removal
efficiency due to fuel pretreatment ('f. R,J
ia included in the overa: I reduction ('f.
R.J. the potential combustion
concentration (PeC) ia determined 88
follows:
(i Sf ~ s;) 7
Is + Z \.:.CV1 - GCV;} 10 ; n9/J
G Sf % S~ 4
PCC Is + Z - - "..".....v 10; 1b/ml111on Btu.
GCV1 GIoL
7.1.4 When inlet monitoring data are is used aa F.... If the epplicable atandard
used and the removal efficiency due to is an allowable percent emission.
fuel pretreatment (')I, R,) is not included calculate the allowable emisaion rate
in the overall reduction in potential (E...J uaing thli following equation:
sulfur dioxide emissions (')I, R.). the r- - " PCC/1oo
potential combustion concentration Where:
(PeC) is determined as follows:
" PCC - Allowable percent emission as
PCC = E.' defined by the applicable standard;
Where: perceat.
E,' = The upper confidence limit of the mean 7.3 Calculale & '/~. To determine
inlet emlSlion rale. 81 determined in
sectioa 8.3. compliance for the reporting period
calculate the ratio:
E" '/r-
Where:
E" , - The lower oonfidenoe limit for the
mean oudet emislloa rates. al defined In
Hclion 8.3: 1111/ (Ib/millioa Dtu).
E... - Allowable emission rate II defined ill
leetion 7.2; 1111/ (Ib/rnillion Dtu).
II E" 'IE... is equal to or Ins lhan 1.0. Ibe
facility ia in compliance; if E" 'IE... il grealer
than 1.0. the facility II DOlin compliance for
tbe reporting period..
I'" Doc. ""'7807 PIIod -" 1:<1-1
8IUJIIQ CODe -.0,,,
PCC
7.2 Determine Allowable Emission
Rates (E",,).
7.2.1 NO.. Uae the allowable
emission rates for NO. as directly
defined by the applicable standard in
terml of nglJ (Ib/million Btu).
7.2.2 50.. Use the potential
combustion concentration (PeC) for so.
as determined in section 7.1. to
determine the applicable emission
standard. If the applicable standard is
an allowable emission rate in nglJ (Ib/
milJ:on Btu). the allowable emission rate
146
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Federal Register I Vol. 44, No. 127 I Friday, June 29, 1979 I Proposed Rules
37'960
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 6O.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
a\'ailable 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. 202-75~2564.
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 wben the
averages opacity exceeds 20 percent.
On December 15, 1977, Southwestern
Public Service Company (SPSC) of
Amarillo, Texas, petitioned the
Administrator under 40 CFR 6O.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 6O.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
averalle durinR t.hl: test indicated results
as high as 3~38% while ur~viouaJY .
recorded value @!unved a maximum of
47.8% on lulv 16, 1977. By letter of
Uecember 5, 1977, SPSC was notified of
the Administrator's rmding and its right
to petition for adjustment of the opacity
standard, which it did in a timely
manner.
Standards of Performance for New
Stationary Sources; Adjustment of
Opacity Standard for Foull Fuel Fired
Steam Generator
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 viola tion 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
Herril1glon "ta lion Unit #1 is a hybrid
system that uses an electrostatic
I!recioitator and a marble bed sCNbber.
Althoitsh the system can be altered to
meet the 20% opacity standard, tbe C8st
of such alteration is excessive in view of
the system's current effectiveness in
meeting a11 NSPS emission limitations
except opacity. Twenty percent opacity
could be achieved only by a four-fold
increase in pressure drop on the marble
bed sCNbber (from 15 em HID to 60 cm
HaD), or by a 30% increase in the
specific collector area of the
electrostatic precipitator. Increasing the
pressure drop to 60 cm HID would
require an additional $1.5 million
annually for operation and maintenance,
and would require that the sCNbber be
redesigned to operate at the increased
pressure drop. Increasing the specific
collector area of the electrostatic
precipitator would cost approximately
an additional S4 million. Since this
facility can meet the mass standard with
tll.e equipment installed, it does not
apoear that the extensive redesi~ and
mcreased costs are warranted.
147
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Rule.
In view of the above. EPA proposes
that SPSC's Harrington Station Unit #1
be excused from comoliance with the
20% opacity standard of 40 CFR
6O.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 35'16 o'paci\y.
except that a maximum of 42'16 opacity
shall be pernllhel1 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. a5 amended 142 V.S.C.
7411 and 7601(a)).
Dated: June 19. 1979
Doug1a8 M Coatle,
Administrator.
In consideration of the foregoing, it is
proposed to amend Part 60 of 40 CFR
Chapter I as follows:
Subpart D-Standardl of Performance
for Foull Fuel-Fired Steam Generators
1. Section 60.42 is amended by adding
paragraph (b](1) as follows:
f 60.42 Stanard for partlcutate matter.
(a) . . .
(b)(1) Southwestern Public Service
Company shall not cause to be
discharged into the atmosphere from its
Harrington Station Unit #1 in Amarillo,
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. 111. 301(a), Clean Air Act 81 amended
(42 V.S.C. 7411, 7601.))
2. Section 6O.45(g)(1) is amended by
adding paragraph (i) as follows:
f 60.45 EmI88Ion and fuel monitoring.
(g)' ..
(1) . . .
(i) For sources subject to the opacity
standard of Section 6O.42(b)(1),
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.
(PR Doc _58 ruoc! 11-211-70: 8.4& ...)
.LUIIO COO£ -.ot-ll
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-1M81
Federal Register I Vo\. 44. No. 154 I Wednesday. August 8. 1979 I Proposed RuIn
46482
ENVIRONMENTAL PROTECT10N
AGENCY
[40 CFR Parts 51 and 52)
[FRL 1084-7, Docket No. OAQPS-79-12J
Emission Monitoring of Stationary
Sources
AGENCY: Environmental Protection
Agency.
ACTION: Advance Notice of Proposed
Rulemakmg.
SUMMARY: Under authority granted m
sections 110. 114. and 301 of the Clean
Air Act. EPA has established a program
of source surveillance and specifically
of continuOl'S mOnitoring for certain
significant stationary sources. Current
programs for source monitoring
genprally do not determme compliance
of sources with emission regulations on
anything but an infrequent basis. This
proposed action arises from the need for
control agencies to be assured that
re~ulated sources are meeting emission
limitations on a continual basis. EPA. in
h~hl of the above. is contemplatm~
act!Ons 10 Improvl!. e)(pand. and
expeclte implementation 01 the
contmuous emiSSion mOnltorm~
requirements lor certam stallonary
sources. Comments are solicited on
specIfic issues and aspects related to
this contemplated action.
DATE: Comments received on or before
October 9. 1979 will be considered by
EPA.
ADDRESS: Comments should be
submitted (in duplicate. if possible) to:
Central Docket Section. (A-130J.
Environmental Protection Agency. 401 M
Street SW.. Washington. DC 20460,
Attention: Docket No. OAQPS-7~12.
Docket No. OAQPS-7~12. containing
material relevant to this rulemaking. is
located in the U.S. Environmental
Protection Agency. Central Docket
Section. Room 2903B. 401 M. Street. SW.
Washington. DC 20460. The docket may
be inspected between 8:00 a.m. and 4:00
p.m. on weekdays and a reasonable fee
ma~ be charged for copying.
FO' .=URTHER INFORMAnON CONTACT:
M, "}arrvl D. Tvler. Environmental
PrOl. ~tion Agency. (MD-15). Research
Triangle Park. North Carolina 27711
Phone: (919) 541-5425.
SUPPLEMENTARY INFORMAnON: The
Environmental Protection Agency
mtends to develop regulations which
will refine and e)(pand certain portions
of Title 40 of the Code of Federal
Regulations. in particular. the
continuous monitoring requirements of
I 51.19(e).ln addition. among other
options. the Agency is contemplating
taking actions which wiIl expedite the
implementation of the continuous
monitoring requirements through the
promulgation of requirements in 40 CFR.
Part 52. and the use of authority granted
to EPA by section 114 of the Clean Air
Act.
Section 110(a)(2)(F) (ii) and (iii) of the
Clean Air Act is the basis for EPA's
State Implementation Plan requirements
found in 40 CFR 51 and 52. This
authority requires State Implementation
Plans to contain legally enforceable
procedures which require owners or
operators of stationary sources to install
equipment to monitor emissions from
such sources and to report the data
obtained. Section 114. which could be
used to expedite implementation of the
source surveillance requirements.
further authorizes the Adminisnator to
require any owner or operator of an
emission source to "install. use. and
maintain such monitoring equipment or
methods. . . as he may reasonably
require. "
By the above regulations and
associated administrative actions.
certam exisllng air pollutant emissIOn
sources would be required 10 install and
properly operate equipment which will
continuously monitor parameters such
as opaeity (a measure of light
attenuation caused by exhaust lIases).
sulfur dioxide. or certain operatmg
parameters with respect to the contrul
equipment.
To expedite the program. sourc... '_,JUld
be required. uy admlni:;trati\C a('tHm. to
install the monitors within one ve,n of
promulgation of the regulations:
aulhority for this requirement lies m
section 114 of the Act. State assumption
of Ihe program would be underlaken as
a follow-up through the routine time
schedules specified under Part 51 of
Title4O.
The primary purpose of this notice is
10 inform interested parties ofEPA's
intent to uegin a process which may
result in additional requirements on
States 10 adopt regulations and
subsequently for sources 10 implement
regulations concerning the measurement
of emissions from stationary sources on
a continual basis. Additionally. this
Nolice solicits comments on the
practicability and Ihe utility of these
potential requirements.
Comment should be addressed. but
not limited. to the following: (a) Is one
year 10 comply with the requirements
sufficient to acquire. install. and test the
momtoring system?
148
(b) What sources should be included
for technical evaluation?
Ic) Will the program be effeclive in
prQviding a qualitative and/or
quantitative basis for ensuring continual
compliance?
(d) WiIllhe air quality benefit.
achieved offset Ihe capital and operating
expenditures required?
(eJ Is fuel analysis a viable option to
monitor SO. emissions for large (greater
than 250 million BTU/HR) boilers?
(0 Fuel analysis procedures and
experiences.
(g) Reliability of continuous
monitoring equipment.
(h) Experience in installation.
operation and maintenance of
continuous monitoring equipment.
(i) The technical feasibility of
continuous monitoring.
(il Allemative methods 10 conlinuous
mOnitoring.
(kJ Experience in use of conllnuous
monitoring data as an enforcement tool.
(I) Quality assurance procedures used
to ensure valid data.
(m) Experience in correl"tin~
continuous monlloring data anJ
performanc~ lest.
(n) Control agency and source
experiences with continuous monitoring
and the benefits derived.
(0) Cost of installation and operation
of continuous monitoring eq:Jipment.
(p) Estimated resource impacts on
States and local air pollullun al/enei"s
and on air pollution sourc!!s: and
Iql Experience to dale with :Iw "". uf
co.:tmuous mass e:T1lssioll mOnltnrs.
C.]mments submiltF.d in accnrd..nct'
with the Septemuer 19. 1978. Fedef:ll
Regisler Proposal on Electric Utility
Steam Generating Units need not ue
resubmitted as these commenls will
automatically be considered during the
regulatory development process.
Copies of the development plan which
serves as Ihe operating plan' for the
proposed regulatory development
process will be available for public
inspection and copying at the EPA
Central Docket Section. Room 2930B.
Waterside Mall. 401 M Street. SW..
Washington. D.C. 20460. The docket
number is OAQPS-7~12 and will be
available to public inspection during
normal business hours.
This advance notice of proposed
rulemaking is issued under the authority
of sections 110. 114. and 301 of the Clean
Air Act.
Dated: August 1. 1979.
Douglas M. Costie.
Administrator.
IFR Doc :"~ZH80 filed 1-7-iq: 8-015 IIml
81WNG COIlE ~1'"
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Federiu Register I Vol. 44. No. 184 I Thursday. September 20, 1979 I Proposed Rules
54507
Proposed Approval 0' an
Administrative Order Issued by the
South Carolina Deparbnent 0' Health
and Environmental Control to the U.s.
Departmem of Energy. Savannal. RIver
Operations Office
AGENCY: Environmental Protecti In
Agency.
ACTION: Proposed rule.
SUMMARY: EPA proposes tu approve an
administrative order issued by the South
Carolina Department of Health and
Environmental Control [DHEC) to the
Savannah River Operations Office
(SROO). The Ord(>~ requires SROO to
bring air emissions from its thirteen
coal-fired stoker boilers in Aiken. South
Carolina into compliance with air
pollution control regulations contained
in the federally approved South Carolina
State Implementation Plan (SIP) by no
laler than June 30. 1979. Because the
order has been issued to a major source
of air pollution and permits B delay in
comphunce with provisions of the SIP.
the Administrative Order must be
approved by EPA before it becomes
effective as a delayed compliance order
under the Clean Air Act (the Act). If
approved by EPA. the order will
constitute an addition to the SIP. In
addition. a source in compliance with an
approved order may not be sued under
the federal enforcement or citizen s"it
provisions of the Act for violations of
the SIP regulations coverett by the order.
The purpose of this notice is to invite
public comment on EPA's proposed
approval of the order as B delayed
compliance order.
DATE: Written comments must be
received on or before October zz. 1979.
ADDRESSES: Comments .hould be
submitted to Director. Enforcement
Division. EPA. Region IV. 345 CourJand
Street. N.E.. Atlanta. Georgia 30308. The
State order. supporting material and
public comments received in response to
this notice may be inspected Bnd copied
(for appropriate charges) at this address
during normal business hours.
FOR FURTHER INFORMATION CONTACT:
William Voshell. Air Enforcement
Branch. U.S. Environmental Protection
Agency. Region IV. 345 Courtland Street
NE., Atlanta. Georgia 30308. Telephone
Number: (404) 881-4298/4253.
SUPPLEMENTARY INFORMATION: SROO,
located at Aiken, South Carolina.
operates 13 coal-fired boilers at its
facility in Aiken and Barnwell County.
On November 30. 1977. EPA issued a
Notice of Violation to SROO for
'Violation of South Carolina Regulation
r ;t~2.6 Standard No. Z. Section I (now
r.~1~2.5. Standard No.1. Section II) and
R61~2.6. Standard No.1. Section I (now
R61~2.5. Standard No.1. Section I).
dealing with the control of particulate
emissions and visible emissions.
respectively. Ongoing negotiations have
continued since 1972. SROO has
acknowledged that 13 of the coal-fired
boilers are. or have been. in violation of
the respective South Carolina regulation
dealing with particulate and/or visible
emissions. SROO further states that its
inability 10 meet said standards is due in
part to its adherence to the federal
budget process. the critical production
requirements of the plant. and the need
to perform tests to determine the
efficiency of the proposed corrective
equipment. For past violation of Ihe
aforementioned provisions of law.
SROO agrees to pav In the South
Carolma OepAr~p.n1oi Health And
Environmental C.o[l.\roL thp sum of one
h"drlld lhree thousand nine hundred
fifty dollars 1$103.950.001 in
I,;onslderatlofl whereof the Department
agrees to waive all claims 10 'any
penalties provided by law which have
or may accrue prior to the expected final
compliance date of July 1. 1979. Final
compliance is to be achieved on or
before July I, 1979.
The Order under consideration
addresses particulate and visible
emissions from the 13 coal-fl1'ed boilers
at Aiken. South Carolina causing
pollution which are subject to South
Carolina Regulations R61~.5, Standard
No.1. Section II. dealing with the control
of particulate emissions from fuel
burning sources. and R61-{!2.5. Standard
No.1. Section I, dealing with the control
of visible emisIJions. respectively. These
regulations limit the emissions of
particulate and visible emissions and
are part of the federally approved South
Carolina State Implementation Plan. The
order requires final compliance with the
regulation by June 30.1979. through the
implemeDtation of the following
schedule for the construction or
installation of control equipment. SROO
agrees to abide by the following
compliance schedule as it relates to
each respective area designated herein.
a. RegardiDg Area l00-c. Unil ;<1,
SROO shall complete the following acts
on or before the dates specified:
(1) February 1. 197~Submit to the
Chief. Bureau of Air Quality Control.
South Carolina. Department of Heallh
and Environmental Control (hereinafter
"Chief'}, acceptable performance lests
certifying compliance with Regula tion
62.5, Standard No.1. Section I and
149
Section II.
b. RegardJ.ng Area 100-C. Urut #2.
SROO shall complele the following acts
on or before the dates specified:
(1) April 27. 1979--Complete oD-site
construction and installation of eIIl.lssion
control equipment and initiate use of
such equipmeDt.
(2) June 1, 1979-Commence
performance tes" and achieve
compliance with the State of South
Carolina Air Pollution Control
Regulations and Standards. Regulation
82.5, Standard No.1. Section I and
Section I!.
(3) June 30. 1979-Submit to the Chief
acceptable performance tests cerllfying
compliance with RegulatioD &2.5,
Standard No.1, Section I and Section II.
c. RegardiDg Area 200-F. Unit ;::1.
SROO shall complete the followmg acts
on or before the dates specified:
(1) March 1. 1979-Submit to the Chief
acceptable performance tests cerl1fying
compliance with Regulation &2.5.
Standard No.1. Section I and Section II.
d. Regarding Area 200-F, Unit ;;2,
SROO shall complete the following acts
on or before the dates specified:
(1) February I, 1979-Submit to the
Chief acceptable performance tests
certifying compliance with Regulation
82.5, Standard No.\. Section J and
Section II.
e. RegardiDg Area 200-F, Unit #3,
SROO shall complete the following acts
on or before the dates llpecified:
(1) February 1. 1979-Submit to the
Chief acceptable performance tests
certifying compliance with Regulation
62.5, StaDdard No.1. Section I and
Section II.
f. Regarding Area 200-F. Unit #4,
SROO shall complete the following ac"
on or before the dates specified:
(1) June 1. 1979-Commence
performance tesls and achieve
compliance with the State of South
Carolina Air Pollution Control
Regulations and Standards, Regulation
62.5. Standard No.1, Section I and
Section II.
(2) June 30, 197~Submit to the Chief
acceptable performance tests certifying
compliance with Regulation 62.5.
Standard No.1. Section I and Section n.
g. Regarding Area 2()(}-H. Unit #1.
SROO shall complete the following acts
on or before the dales specified:
(1) February 1, 1979-Commence
performance tests and achieve
compliance with the State of South
Carolina Air Pollution Control
Regulations and Standards. Regulation
82.5. Standard No. I, Section I and
Section II.
-------
54508
. I V I 44 No 184 I Thunday, September 20, 1979 I Proposed Rules
Federal Register 0 . , .
(2) March 1. 1979-Submit to th~ Chief'
acceptable performance tests cerl1fymg
comphance with Regulallon 62.5. .
Standard No.1. Section I and ~Cl1on D.
h. Regarding Area ~H. Umt #2.
SROO shall complete the following ac"
on or before the da tes specified:
(1) February 1. 1979-Submit to the
Chief acceptr.ble performance test~
certifving compliance with Regulation
62.5. Standard No.1, Section I and
Section II.
i. Regarding Area ~H. Unit #3.
SROO shall complete the following acts
on or before the dates specified:
(1) February 26. 197~lnitiate ~n-~ite
construction or installation of emISSion
control equipment.
(2) April 30. 1979-Complete on-~ite.
construction and installation of e!DI8810n
control equipment and initiate use of
luch equipment
(3) June 1, 1979-Commence
performance tests and achieve
compliance with the State of South
Carolina Air Pollution Control
Regulations and Standards. Regulation
62.5. Standard No.1. Section I and
Section II.
(4) lune 30, 1979-Submitto the .C~ief
acceptable performance testl certifymg
compliance with Regulation 62.5.
Standard No.1, Section I and Section U.
j. Regarding Area 100-K. Unit #1,
SROO shall complete the following actl
on or before the dates apecified:
(1) June 1. 1979-Commence
performance t8ltl and acl1teve
compliance compliance with the State of
South Carolina Air Pollution Control
Regulations and Standardl. Regulation
62.5. Siandard No.1. Section I and
Section U.
(2) June 30. 1979-Submit to the Chief
acceptable performance tests certifying
compliance with Regulation 62.5.
Siandard No.1. Section I and Section D.
It. Regarding Area 100-K. Unit #2.
SROO will complete the following acta
on or before the dates specified:
(11 February 1, 1979-Submit to the
Chief acceptable performance tests
certifying compliance with Regulation
62.5. Standard No.1, Section I and
Section U.
1. Regarding Area 100-II Unit #1.
SROO shall complete the followm, acta
on or before the dates specified:
(11 February 1. 1979-Submit to the
Chief acceptable performance teltl
certifying compliance with Regulation
62.5. Standard No. I, Section I and
Section n.
m. Regarding Area l00-P. Unit #2,
SROO shall complete the following act.
on or before the date. .pecified:
(11 February 1. 1979-Commence
performance tests and achieve
compliance with the State of South
Carolina Air Pollution Control
Regulation. and Standards. Regulation
62.5. Standard No.1. Section I and
Section U.
(21 March 1, 1979-5ubmit to the Chief
acceptable performance testl certifying
compliance with Regulation 62.5.
Siandard No. I, Section f and Section U.
The lource haa conlented to the terms
of the order and haa agreed to meet the
Order'l incrementl during the period of
thil informal rulemakina. The louree il
required-to .ubmit quarterly reportl by
the 15th day of the followil18 quarter
indicating progresl toward each
mileltone in the Ichedule of compliance.
U any delay il anticipated in meetil18
laid milestonel. the SROO Ihall
Immediately notify the DHEC in writing
of the anticipated delay and realonl
therefor. Notification of the delay Ihall
not excuse the delay. In addition. SROO
Ihall lubmit. no later than 30 day. after
the deadline for completing each
milestone required by the above
Ichedule certification, to the DHEC
whether or not luch mileltone haa been
met.
AI an interim control meaaure, the
SROQ will continue the program
directed at minimizing adverle impact
on ambient air quality. The interim
control program Include. the followm,
elementl:
II) The continued Implementltion of
menurel thlt relult in the mlximum
prlcticable reduction of plfticulate malter
emillionl Ilncludill8 IUch Iltematives al
load lhiftill8. 10ld reduction. ule of lower ..b
coal, and the continuina program of control
equipmenl maintenance);
150
(b) The continued Implementation of a fuel
IUppl)' quality allurance program d~ted at
reduclna fuel VlriabiUty and optiJaizlna fuel
CJuality will be initiated:
Ie) The continued operation of exlat!JII,
continuoU8 o,padt)' monlto"", equipment
and
Id) The development 01 an appropriate
1)'ltem of reporl\na aU elemenll of the
program developed pursuant 10 the
requirements Italed berelnabove.
Bacau.e !hil Order has been issued to
a major lource of particulate emissions
and permitl a delay in compliance with
the applicable state air pollution control
regulations, it must be approved by EPA
before it becomes effective al 8 delayed
compliance order under Section 113(d)
of the Clean Air Act (the Act). EPA may
approve the order only if it latisfies the
appropriate requirements of thil
lubsection. EPA has tentatively
determined that the above-referenced
order satisfies these legal requirements.
U the lubmitted administrative Order
is approved by EPA. source compliance
with its terms would preclude federal.
enforcement action under Section 113 of
the Act against the source for violation.
of tAe regulation/s) covered by the Order
duril18 the period the Order i. in effect.
Enfo~cement against the source under
the citizen luit provision of the Act
(Section 3(6) would be .imilarly
precluded. If approved. the Order would
also constitute an addition to the Soutb
Carolina SIP. Compliance with the
proposed Order will not exempt the
company from the requirements
contained in any .ubsequent revision to
the SIP which are approved by EPA.
All interested persons are invited to
.ubmit written comments on the
proposed Order. Written commentl
received by the date specified above
will be considered in determinlna
whether EPA may approve the Order.
After the public comment period, the
Administrator of EPA will publish In the
Federal Resister the ABencY'1 final
action on the Order in 40 CFR Part 65.
(.2 U.S.c. 7.13, 7601)
Dated: September 13, 1979.
Joim C. WhIte.
Regional Administrator. Region IV.
In Doc. ~ PlIed ..,..,.,......)
8IUJIIG CODE -..,...
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55651
Federal Register / Vol. 44. No. 189 / Thursday. September 27. 1979 / Notices
Montana Power Co., Colstrlp Units No.
3 and No.4; Approval of PSD Permit
Notice is hereby given that on
September 11. 1979. the U.S.
Environmental Protection Agency issued
a Prevention of Significant Deterioration
(PSD) permit to the Montana Power
Company, Butte, Montana. to construct
Colstrip Units #3 and #4. two 778
megawatt (gross) coal fired steam
electric generating plants at Colstrip.
Montana. This permit has been issued
under EPA's Prevention of Significant
Deterioration Regulations (40 CFR. Part
52.21J subject to certain conditions. as
summarized below:
1. SO. emissions from either unit shall
not exceed 761 pounds per hour (runntn~
3D-dav aver"se) or 0.16 pounds per
million BTU heat input as a\eraged over
any calendar day. to be exceeded no
more than once during any calendar
month. Comoliance with these limits
will be based solei v on continuous
emissIOn mOnItor (CEMl d...ta.
2. Particulate matter emissIons from
either unit shall not exceed 0.05 pounds
per million BTU heat input as averaged
over three hours (minimum) of reference
method testing: and 20 percent opacity.
Comoliance will be based on Rpfprence
Method 5: and Rp;"renre \leLhod 9 and
CEM data, respectively.
3. Nox emissions from eIther unit shall
not exceed 0.70 pounds per mIllion BTU
heat input. as averaged over any
calendar day. Compliance to be based
solelv on CEM data.
4. A CEM system for measuring
opacity, optical density. sulfur dioxide.
nitrogen oxides. and dIluent shall be
installed, calibrated. maintained and
operated by the Company.
5. The Company shall submit to EPA
all future information and final plans for
the SO. and particulate control system.
If EPA determines that the emission
limits will not be met. the permit shall
be denied ob initio.
6. The Company shall establish an air
qUlllity and meteorology mOnItoring
network.
The following conditions were added as
a result of proceedln~s conducted
pursuant to Section 1&4(e) of the Clean
Air Act. Should the Northern Chevenne
Reservation be redesignated to a~y PSD
classification less slrln~enl than Class I
Conditions 7. 8 and 9 shall be of no force
IInd effect. Howe\"er. and controls
desIgned and implemf'n!l'd pursuant 10
Condltons 7 and 8 prior 10 such
redesignatlon shall rpmal'] operable.
7. Colstrip Units =3 and =4 will he
suuject to the best a\"ailaLl,' rdlUflt
technology (BART) requirements for
nitrogen oXides at such time as EPA
promulgates these requirements for
power plants.
8. If therp is a perce;:>tlu!p plume (as
will be specified In EI'A \'is,bllity
regulations) on the Northern Cheyenne
Indian Reservation. as ousprved by an
impartial observer designated by EPA.
Units #3 and #4 will be subiect to the
151
BART requirements for particulate
mdtler.
9. The Company and Northern
Ch!'yenn!' Tribe shall work tog!'lhPr to
d~fme a basehne and operational
\'Islbllll\' mOnltorin,g program. ThIs
program is to be funded by tnI'
Company.
This nohce cont...ins onl)" a <'ll1lI11ar}'
of the pprmlt conditions and mt~esll'd
parties are advIsed 10 review thl' full
pf'rmit. This PSLJ permil is reviewable
under Sl'ction 307(u)(1) of the Clean Air
Act only in the Ninth C,rcuil Court of
Appl'als. A petition for rev iew must be
filed on or before November 26. 19~9.
Copies of the permit are available for
public inspection upon request at thl'
following locations:
Environmental Proteclton Agency. Reg;"n
VIII. A.. Programs Branch. Room 204 1860
Lincoln Street Denver. CO 802951303) 837-
3783
Montana Air Quality Bureau. Department of
Uealth II Environmental SCiences.
Cogswell Building. Helena." Montana 59601
(4Ob1449-3454
Rosebud County Clerk's Office. Rosebud
County Courthouse. Fors~ tho Montana
59327 (4061 35&-7318.
Dated: September 21. 19~9
Roger L William..
Regional AdmlO/slrolor.
Int Ooc.. ?'8-8J6l FI"'d u.-",,'~ 8 45 8ml
IIIU..- COO( U4MH1HIII
-------
Wednesday
October 10, 1979
Part II.
Environmental
Protection Agency
Standards of Performance for New
Stationary Sources; Continuous
Monitoring Performance Specifications
153
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58602
Federal Register I Vol. 44. No. 197 I Wednesday, October 10, 1979 I Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
(FRL 1276-4J
Standards of Performance for New
Stationary Sources; Continuous
Monitoring Performance
Specifications
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Revisions.
SUMMARY: On October 6.1975 [40 FR
46250). the EPA promulgated revisions to
40 CFR Part 60. Standards of
PerCormance for New Stationary
Sources. to establish specific
requirements pertaining to continuous
emission monitoring. An appendix to the
regulation contained PerCormance
Specifications 1 through 3. which
detailed the continuous monitoring
instrument performance and equipment
specifications. installation requirements.
and test and data computation
procedures for evaluating the
acceptability of continuous monitoring
systems. Since the promulgation of these
perCormance specifications. the need for
a number of changes which would
clanCy the specification test procedures.
equipment specifications. and
momtoring system installation
requirements has become apparent. The
purpose oC the reviaions is to
incorporate these changes into
Performance Specifications 1 through 3.
The proposed revisions would apply
to all monitoring systems currently
subject to performance specifications 1.
2. or 3. including sources subject to
Appendix P to 40 CFR Part 51.
DATES: Comments must be received on
or be Core December 10. 1979.
ADDRESSES: Comments. Comments
should be submitted (in duplicate if
posSIble) to the Central Docket Section
(A-130). Attn: Docket No. OAQPS-79-4.
U.S. Environmental Prl)tection Agency,
401 ~f Street. S.W.. Washington. D.C.
20460.
Docket. Docket No. OAQPS-79-4,
containing material relevant to this
rule making. is located in tbe U.S.
Em ')nmental Protection Agency.
Cer, 11 Docket Section. Room 29038. 401
M St! 'et. S.W.. Washington. D.C. The
docke, may be inspected between 8
A.M. and 4 P.M. on weekdays. and a
reasonable Cee may be charged for
copy mg.
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin. Director. Emission
Standards and Engineermg Division
(MD-13). Environmental Protection
Agency. Research Triangle Park. North
Carolina 27711. telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION: Changes
common to all three of the performance
specifications are the clarification of the
procedures and equipment
specifications. especially the
requirement for intalling the continuous
monitoring sample interface and of the
calculation procedure for relative
accuracy. Specific changes to the
specifications are as follows:
Performance Specification
1. The optical design specification fo'
mean and peak spectral responses and
for the angle of view and projection
have been changed from "SOD to 600 nm'
range to "515 to 585 nm" range and from
"5." to "3.". respectively.
2. The following equipment
specifications have been added:
a. Optical alignment sight indicator
for readily checking alignment.
b. For instruments having automatic
compensation for dirt accumulation on
exposed optical surfaces. a
compensation indicator at the control
panel so that the permissible maximum
4 percent compensation can be
determined.
c. Easy access to exposed optical
surfaces for cleaning and maintenance.
d. A system for checking zero and
upscale calibration (previously required
in paragraph 60.13).
e. For systems with slotted tubes. a
slotted portion greater than 90 percent of
effluent pathlength (shorter sloll are
permitted if shown to be equivalent).
f. -An equipment specification for Ihe
monitoring system data recorder
resolution of <5 percent of full scale.
3. A procedure for determining the
acceptability of the optical alignment
sight has been specified; the optical
alignment sight must be capable of
indicating that the instrument is
misaligned when an error of %2 percent
opacity is caused by misalignment of the
instrument at a pathlength of 8 meters.
4. Procedures for calibrating the
attenuators used during instrument
calibrations have been added; these
procedures require the use of a
laboratory spectrophotometer operating
in the ~7oo nm range with a detector
angle view of <10 degrer:s and an
accuracy of 1 percent.
5. The following changes Itave been
made to the procedures for the
operational test period:
a. The requirement for an analog strip
chart recorder during the performance
tests has been deleted: all data are
collected on the monitoring system data
recorder.
154
b. Adjustment of the zero and span at
24-hour intervals during the drift tests is
optional; adjustments are required only
when the accumulated drift exceeds the
24-hour drift specification.
c. The amount of automatic zero
compensation for dirt accumulation
must be determined during the 24-hour
zero check so that.the actual zero drift
can be quantified. The automatic zero
compensation system must be operated
during the performance test.
d. The requirement for offsetting the
data recorder zero during the
operational test period has been deleted.
e. Off the stack "zero alignment" of
the instrument prior 10 installation is
permitted,
Performance Specification 2
1. "Continuous monitoring system"
has been redefined to include the
diluent monitor, if applicable. The
change requires that the relative
accuracy of the system be determined in
terms of the emission standard. e.g..
mall per unit calorific value for fossil-
fuel fired steam generators.
2. The applicability of the test
procedures excludes single-pass. in-situ
continuous monitoring systems. The
procedures for determining the
acceptability of these systems are
evaluated on a case-by-case basis.
3. For extractive systems with diluent
monitors. the pollutant and diluent
monitors are required to use the same
sample interface.
4. The procedure for determining the
acceptability of the calibration gasel
has been reviled. and the 20 percent
(with 95 percent confidence interval)
criterion has been changed to 5 percent
of mean value with no single value being
over 10 percent from the mean.
5. For low concentrations. a 10 percent
of the applicable standard limitation for
the relative accuracy has been added.
8. An equipment specification for the
system data recorder requiring that the
chart scale be readable to within <0.50
percent of full-scale has been added.
7. Instead of spanning the instrument
at 90 percent of full-scale. a mid-level
span is required.
8. The response time test procedure
has been revised and the difference
limitation between the up-scale and
down-scale time has been deleted.
9. The rela tIve accuracy test
procedure has been revised to allow
different tests (e.g.. pollutant, diluent.
moisture) during a I-hour period to be
correlated.
10. A low-level drift may be
substituted for the zero drift teat.
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Federal Register I Vol. 44. No. 197 I Wednesday. October 10. 1979 I Proposed Ru)es
58603
Perfonnaoat Specificatioo 3
1. The applicability of the test
procedures has been limited to those
munitors that introduce calibration
gases directly into the analyzer and are
used a8 diluent monitors. Alternative
procedures for other types of monitors
are evaluated on a case-by-case basis.
2. Other chanaes were made to be
consistent with the revisions under
Performance Specification 2
The proposed revised performance
specifications would apply to a11 sources
subject to Performance Specifications 1.
2. or 3. These include sources subject to
standards of performance that have
already been promulgated and sources
subject to Appendix P to 40 CFR Part 51.
Since the purpose of these revisions is to
clarify the performance specifications
which were promulgated on October 6.
1975. not to establish more stringent
requirements. it is reasonable to
conclude that most continuous
monitoring instruments which met and
can continue to meet the October 6.
1975. specifications can also meet the
revised specifications.
Under Executive Order 12044, the
Environmental Protection Agency is
required to judge whether a regulation is
"significant" and therefore subject to the
procedural requirements of the Order or
whether it may follow other specialized
development procedures. EPA labels
these other regulations "specialized". I
have reviewed this regulation and-
determined that it is a specialized
regulation not subject to the procedural
requirements of Ex!!cutive Order 12044.
Dated: October 1. 1979.
Douglu M. Coall..
Adm;n;slrolor.
It is proposed to revise Appendix B.
Part 60 of Chapter I. Title 40 of the Code
of Federal Regulations as follows:
Appendix B-Performance
Specifications
Performonce Specification 1-
Specifications and Test Procedures For
Opacity Continuous Monitoring System!f
in Stationary Sources
1. Applicability and Principle
1.1 Applicability. This Specification
contains instrument design.
performance. and installa tion
requirements. and test and data
computation procedures for evaluating.
the acceptability of continuous
monitoring systems for opacity. Certain
design requirements and test procedures
established in the Specification may not
be applicable to a11 instrument designs;
equivalent systems and test procedures
may be used with prior approval by the
Administrator.
1.2 Principle. The opacity of
particulate matter in stack emissions is
continuously monitored by a
measurement system based upon the
principle of transmissometry. Light
having specific spectral characteristics
is projected from a lamp through the
effluent in the stack or duct and the
intensity of the projected light is
measured by a sensor. The projected
light is attenuated due to absorption and
sca tter by the particula te ma tter in the
effluent: tbe percentage of visible light
attenuated is defined as the opacity of
the emission. Transparent stack
emissions that do not attenuate light will
have a transmittance of 100 percent or
an opacity of zero percent. Opaque
stack emissions that attenuate all of the
visible light will have a transmittance of
zero percent or an opacity of 100
percent.
This specification establishes specific
design criteria for the transmissometer
system. Any opacity continuous
monitoring system that is expected to
meet this specification is first checked to
verify that the design specifications are
met. Then. the opacity continuous
monitoring system is calibrated.
installed. an operated for a specified
length of time. During this spe_cified time
period. the system is evaluated to
determine conformance with the
established performance specifications.
2. Definitions
2.1 Continuous Monitoring System.
The total equipment required for the
determinahon of opacity. The system
consists of the following major
subsystems:
2.1.1 Sample Interface. That portion
of the system that protects the analyzer
from the effects of the stack effluent and
aids in keeping the optical surfaces
clean.
2.1.2 Anatyzer. That portion of the
system that senses the pollutant and
generates a signal output that is a
function of the opacity.
2.1.3 Data Recorder. That portion of
the system that processes the analyzer
output and provides a permanent record
of the output signal in terms of opacity.
The data recorder may include
automatic data reduction capabilities.
2.2 Transmissometer. That portion of
the system that includes the sample
interface and the analyzer.
2.3 Transmiltimce. The fraction of
incident light that is transmitted through
an optical medium.
2.4 Opacity. The fraction of incident
light that is atlenuated by an optical
medium. Opacity lOp) and
transmittance ITr) are related by:
Op=1-Tr.
155
2.5 Optical Density. A logarithmic
measure of the amount of incident light
allenuated. Optical density (D) is
related to the transmittance and opacity
as follows:
D= -log.. Tr= -Iogoo (1-0pl
2.6 Peak Spectral Response. The
wavelength of maximum sensitivity of
the transmissometer.
2.7 Mean Spectral Response. The
wavelength which bisects the total area
under the effective spectral response
cUnie of the transmissometer.
2.8 Angle of View. The angle that
contains all of the radiation detected by
the photodetector assembly of the
analyzer at a level greater than 2.5
percent of the peak detector response.
2.9 Angle of Projection. The angle
that contains all of the radiation
projected from the lamp assembly of the
analyzer at a level of greater than 2.5
percent of the peak illuminace.
2.10 Span Value. The opacity value
at which the continuous monitoring
system is set to produce the maximum
data display output as specified in the
applicable subpart.
2.11 Upscale Calibration Value. The
opacity value at which a calibration
check of the monitoring system is
performed by simulating an upscale
opacity condition as viewed by the
receiver.
2.12 Calibration Error. The
difference between the opacity values
indicated by the continuous monitoring
system and the known values of a series
of calibration allenuators (filters or
screens).
2.13 Zero Drift. The difference in
continuous momtoring system output
readings before and after a stated period
of normal continuous operation dunng
which no unscheduled maintenance.
repair. or adjustment took place and
when the opacity (simulated) at the time
of the measurements was zero.
2.14 Calibration Drift. The difference
in the continuous monitoring system
output readings before and after a stated
period of normal continuous operahon
during which no unscheduled
maintenance. repair. or adjustment took
place and when the opacity (simulated)
at the time of the measurements was the
same known upscale calibration value.
2.15 Response Time. The amount of
time it takes the continuous monitoring
system to display on the data recorder
95 percent of a step change in opacity.
2.16 Conditioning Period. A period of
time (168 hours minimum) during which
the continuous monitoring system is
operated without unscheduled
maintenance. repair. or adjustment prior
to initiation of the operational test
period.
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58604
Federal Register I Vol. 44. No. 197 I Wednesday, October 10. 1979 I PropoS"ed Rules
2.17 Operational Test Period. A
period of time (168 hours) during which
the continuous monitoring system is
expected to operate within the
esta blished performance specifications
without any unscheduled maintenance,
repair, or adjustment.
2.18 Pathlength. The depth of
effluent in the light beam between the
receiver and the transmitter of a single-
paBB trar:smissometer. or the depth of
effluent between the transceiver and
renector of a double-pass
transmissometer. Two pathlengths are
referenced by this Specificahon as
follows:
2.18.1 Monitor Pathlength. The
pathlength at the installed location of
the continuous monitoring system.
2.18.2 Emiuion Outlet Pathlength.
The pathlength at the location where
emiSSions are released to the
atmosphere.
3. Apparatus
3.1 Continuous Monitoring System.
Use any continuous monitoring system
for opacity which is expected to meet
the design specifications in Section 5
and the performance specifications in
Section 7. The data recorder may be an
analog strip chart recorder type or other
suitable device with an input signal
range compatible with the analyzer
output.
3.2 Calibration Attenuators. Use
optical filters with neutral spectral
characteristics or screens known to
produce specified optical densities to
vIsible light. The attenuators must be of
sufficient size 10 attenuate the entire
light beam of the Iransmlssometer.
Select and calibrate a minamum of three
attenuators according to the procedures
in Sections 8.1.2. and 8.1.3.
3.3 Upscale Calibration Value
Attenuator. Use an optical filter with
neutral spectral characteristics. a
screen, or other device that produces an
opacity value (corrected for pathlength.
if necessary) that is greater than the sum
of the applicable opacity staftdard and
one-fourth of the difference between tbe
opacity standard and the Instrument
span value. but leu than the sum of the
opacity standard and one-half of the
difference between the opacIty standard
and e instrument span value.
3., Calibration Spectrophotometer.
To ca. brate the calibration attenuators
use a I .boratory spectrophotometer
meeting the following minimum design
specification:
P8tIlT'l8I8f
S".C:"iCa-
WIW818ngth 'Inca'
081«101' 11'19" Of VI8W
Accuracy
. .. 400.100"",
.... S 10'
.... S050Cl-
4. Installation Specificationa
Install the continuous monitoring
system where the opacity meaaurementa
are representative of the total emiasiona
from the affected facility. Use a
measurement path that representa the
average opacity over the cross section.
Those requirements can be met as
follows:
4.1 Measurement Location. Select a
measurement location that ia (a)
downstream from all particulate control
equipment; (b) where condensed water
vapor is not present; (c) acceuible in
order to permit routine maintenance;
and (d) free of interference from
ambient light (applicable only if
transmillometer is responsive to
ambient light).
4.2 Measurement Path. Select a
measurement path that passes through
the centroid of the croll section.
Additional requirements or
modifications must be met for certain
locations as follows:
4.2.1 If the location is in a straight
vertical section of stack or duct and is
less than 4 equivalent diametera
downstream or 1 equivalent diameter
upstream from a bend, use a path that is
in the plane defined by the bend.
4.2.2 If the location is in a vertical
section of stack or duct and is less than
4 diameters downstream and 1 diameter
upstream from a bend. use a path in the
plane defined by the bend upstream of
the transmiuometer.
4.2.3 If the location is in a horizontal
section of duct and is at least 4
diameters downstream from a vertical
bend. use a path in the horizontal plane
that is one-third the distance up the
vertical axis from the bottom of the duct.
4.2.4 If the location is in a horizontal
section of duct and is less than 4
diameters downstream froin a vertical
bend. use a path in the horizontal plane
that is two-thirds the distance up the
vertical axis from the bottom of the duct
for upward now in the vertical section,
and one-tbird the distance up the
vertical axis from the bottom of the duct
for downward now.
4.3 Alternate Locationa and
Measurement Paths. Other locations and
measurement paths may be selected by
demonstrating to the Administrator that
the average opacity mPB~'1red at the
alternate loc~ion or path is equivalent
(:!: 10 percent) to the opacity as
measured at a location meeting the
cn teria of Sections 4.1 and 4.2. To
conduct this demonstration. measure the
opacities at the two locations or paths
for a minimum period of two hours. The
opacities of the two locations or paths
may be measured at different times. but
156
must be measured at the same process
operating conditions.
5. Design Specifications
Continuous monitoringaystems for
opacity must comply with the following
design specifications:
5.1 Optics.
5.1.1 Spectral Response. The peak
and mean spectral reaponses will occur
between 515.nm and 585 nm.. The
response at any wavelength below 400
nm or above 700 nm will be Ie sa than 10
percent of the peak spectral response.
5.1.2 Angle of View. The total angle
of view will be no greater than 4
degrees.
5.1.3 Angle of Projection. The total
angle of projection will be no greater
than 4 degrees.
5.2 Optical Alignment sight. Each
analyzer will provide some method for
visually determining that the instrument
is optically aligned. The syslem
provided will be capable of indicating
that the unit is misaligned when an error
of % 2 percent opacity occurs due to
misalignment at a monitor pathlength of
eight (8) meters.
5.3 Simulated Zero and Upscale
Calibration System. Each analyzer will
include a system for simulating a zero
opacity and an upacale opacity value for
the purpose of performing periodic
checks of the transmisaometer
calibration while on an operating stack
or duct. This calibration system will
provide. as a minimum. a system check
of the analyzer internal optics and all
electronic circuitry including the lamp
and photodetector assembly.
5.4 Access to External Optics. Each
analyzer will provide a means of access
to the optical surfaces exposed to the
effluent stream in order to permit the
surfaces to be cleaned without requiring
removal of the unit from the source
mounting or without requiring optical
realignment of the unit.
5.5 Automatic Zero Compensation
Indicator. If the monitoring system has a
feature which provides automatic zero
compensation for dirt accumulation on
exposed optical surfaces. the system
will also provide some means of
indicating that a compensation of
4 % 0.5 percent opacity has been
exceeded; this indicator shall be at a
location accessible to the operator (e.g.,
the data output terminal). During the
operational test period. the system must
provide some means for determining the
actual amount of zero compensation at
the specified 24-hour intervals so that
the actual 24-hour zero drift can be
determined (see Section 8.4.1).
5.6 Slotted Tube. For
transmissometers that use slotted tubes.
the length of the slotted portion(s) must
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58605
Federal Register I Vol. 44. No. 191 I Wednesday. October 10. 1979 I Proposed Rules
be equal to or greater than 90 percent of
the monitor path length. and the slotted
tube must be of sufficient size and
orientation so as not to interfere with
the free flbW of ernuentthrough the
entire optical volume of the
transmissometer photodetector. The
manufacturer must also show that the
transmissometer uses appropriate
methods to minimize light reflections; as
a minimum. this demonstration shall
consist of laboratory operation of the
transmlssometer both with and without
the slotted tube in position. Should the
operator desire to use a slotted tube
design with a slotted portion equal to
less than 90 percent of the monitor
pathlength. the operator must
demonstrate to the Administrator that
acceptable results can be obtained. As a
minimum demonstration, the ernuent
opacity shall be measured using both
the slotted tube instrument and another
instrument meeting the requirement of
this specification but not of the slotted
tube design. The measurements must be
made at the same location and at the
same process operating conditions for a
minimum period of two hours with each
instrument. The shorter slotted tulfe may
be used if the average opacity measured
is equivalent(:t: 10 percent} to the
opacity measured by the non-slotted
tube design.
6. Optical Design Specifications
Verifciation Procedure.
These procedures will not be
applicable to all designs and will require
modiFication in some cases; all
modifications are subject to the
approval of the Administrator.
Test each analyzer for conformance
with the design specifications of
Sections 5.1 and 5.2 or obtain a
certificate of conformance from the
analyzer manufacturer as follows:
6.1 Spectral Response. Obtain
detector response, lamp emissivity and
£ilter transmittance data for the
components used in the measurement
system from their respective
manufacturers.
6.2 Angle of View. Set up the
recei ver as specified by the
manufacturer's written instructions.
Draw an arc with radius of 3 meters in
the horizontal direction. Using a small
(less than 3 centimeters) non-directional
light source, measure the receiver
response at 4-centimeter intervals on the
arc For 24 centimeters on either side of
the detector centerline. Repeat the test
in Ihe vertical direction.
6.3 Angle of Projection. Set up the
projector as specified by the
manufacturer's written instructions.
Draw an arc with radius of 3 meters in
the horizontal direction. Using a small
(less than 3 centimeters) photoelectric
light detector. measure the light
intensity at 4-centimeter intervals on the
arc for 24 centimeters on either side of
the light source centerline of projection.
Repeat the test in the vertical direction.
6.4 Optical Alignment Sight. In the
laboratory set lip the instrument as
specified by the manufacturers written
instructions for a monitor pathlength of
8 meters. Assure that the jnstrument has
been properly aligned and that a proper
zero and span have been obtained.
Insert an attenuator of 10 percent
(nominal) opacity into the instrument
pathlength. Slowly misalign the
projector unit until a positive or negative
shirt of two percent opacity is obtained
by the data recorder. Then, following
the manufacturer's written instructions.
check the alignment and assure that the
alignment procedure does in fact
indicate that the instrument is
misaligned. Realign the instrument and
follow the same procedure for checking
misalignment of the receiver or
retroreflector unit.
6.5 Manufacturer's Certificate of
Conformance (Alternative to above).
Obtain from the manuFacturer a
certificate of conformance which
certifies that the first analyzer randomly
sampled from each month's production
was tested according to Sections 6.1
through 6.3 and satisFactorily met all
requirements of Section 5 of this
Specification. IF any of the requirements
were not met. the certificate must state
that the entire month's analyzer
production was resampled according to
the military standard 105D sampling
procedure (MIL-STD-l05D) inspection
level II; was retested for each of the
applicable requirements under Section 5
of this Specification; and was
de~ermined to be acceptable under MIL-
STD-105D procedures. acceptable
quality level 1.0. The certificate of
conFormance must include the results of
each test performed for the analyzer(s)
sampled during the month the analyzer
being installed was produced.
7. Performance Specifications
The opacity continuous monitoring
system performance specifications are
listed in Table 1-1.
Tsbl8 1-1.-P..-fOl7llsncB spBCIf,catlOnlJ
Parameter
Speat""'bOnO
~ ~=': =~::::::::.:::::~::::::'::::. ~ ~rl8C='
3 CondotIafwIg-'...................... ,. '88 IIOurI.
- Oper---'................" '88-
5. Z- dnft (2--hau<)' ...................... S 2 pel "'*""
157
TIIbI8 1-1.-PerlomIance $p«IflCatJOnlJ-Gontonued
Pltomo18<
Specmcatlont
8 CaIb-.- dnft 12"',ou'I'.. ......
7 Olta recorCl8r r8lQtubOn .
S 2 pel oo."'ty
S 0 SO pel of lull SCali
spa" Yllue
. EIP'ftMd II un of 8bto8utl mean and Ihe 95 Q8fcent
conhd8nC8 Inlerwal.
. Ounng hi condIbOftIng and op8flb0n81 I..' penodt lhe
COf'ItJnu0u8 tnanltonng sysl8m shall not r8QUWI any COI'T8CI....8
mIItnl8f\8nc8. rep.., replacem8nl 01 8dllJltm8nl other than
thet cturty spec.i.. II roub". and reQuved '" the Opet'ItK>n
and m8N"l1enanc8 manual..
8. Performance Specification
Verification Procedure
Test each continuous monitoring
system that conforms to the design
specifications (Section 5) using the
following procedures to determine
conFormance with the performance
specifications of Section 7.
8.1 Preliminary Adjustments and
Tests. Prior to installation of the system
on the stack. perform these steps or tests
at the affected facility or in the
manufacturer's laboratory.
8.1.1 Equipment Pr~paration. Set up
and calibrate the monitoring system For
the monitor path length to be used in the
installation as speciFied by the
manuFacturer's written instructions. 11
the monitoring system has automatic
pathlength adjustment. Follow the
manufacturer's instructions to adjust the
signal output from the analyzer to
equivalent values based on the emission
-outlet pathlength. Set the span at the
value specified in the applicable
subpart. At this time perform the zero
alignment by balancing the response of
the continuous-monitoring system so
that the simulated zero check coincides
with the actual zero check performed
across the simulated monitor pathlength.
Then. assure that the upscale calibration
value is within the required opacity
range (Section 3.3).
8.1.2 Calibrated Atlenuator
Selection. Based on the span value
specified in the applicable subpart.
select a minimum of three calibrated
atlenuators (low. mid. and high ranRe!
using Table 1-2. If the system is
operating with automatic pathlength
compensation. calculates the allenuator
values required to obtain a system
response equivalent to the applicable
values shown in Table 1-2: use equation
1-1 For the conversion. A series of filters
with nominal optical density (opacity)
values of 0.1(20).0.2(37),0.3(50). 0.4(60),
0.5(66}, 0.6(75}. 0.7(60}, 0.6(84). 0.9(66).
and 1.0(90) are commercially available.
Within this limitation of Filter
availability. select the calibrated
-------
58606
Federal Regisler I Vol..44. No. 197 I Wednesday, October 10. 1979 I Proposed Rules
attenuators having the values given in
Table 1-2 or having valuesclosest to
those calculated by Equation 1-1.
rlbl. 1-2.-Rf!QUtTtKi Cahbr.tlKf A".",..tor V.u-
(Nom"'./)
s.... -
lpero:;..."op.acttyl
c.ht:WI18d 1nenu.llor
--
,.....- -
"_I
Low.rang. o.~.. """eng8
50
60
70
~
'10
'00
0' 1201
, 1201
, 1201
, 1201
, (20)
, 1201
02 (37)
2 (37)
.3 (50)
.3 (501
. IISOI
. (80)
03 150)
3 (50)
. 1801
I 1751
7 1801
g Cl71..J
D. = D,IL.!L,)
Where
D. = Nomllldl optical density value of
reqUired mid. low. or high range
cJllbratwn altenualon.
D, = Des lied attenuata. opllcal dens. I,
oulpul vdlue Irom Table 1-2 8t the lpaa
requlled by Ihe applicable subpart.
L. = ~onllor palhlenglh.
1.,= EmISSion oullel palhlength.
8.1.3 Allenuator Calibration.
Calibrate the required filters or screeru
using a laboratory spectrophotometer
meetln!! the specifications of Section 3.4
10 measure the transmittance in the 400
to 700 nm wavelength range; make
measurements at wavelength intervals
of 20 nm or less. As an alternale
procedure use an Instrument meeting the
specifications of Section 3.4 to mhsure
the C.I E. Daylightc Luminous
Transmittance of the allenuators. During
the calibration procedure assure that a
minimum of 75 percent of the total area
of the altenuator IS checked. The
dltenuator manufacturer must specif)'
the penod of time over which the
altenuator values caD be considered
stable. as well as any special handling
and storing procedures required to
enhance atteDuator stability. To assure
stability. allenuator values must be
rechecked at intervals less thaD or equal
to the penod of stability guaranteed by
the manufacturer. However. values must
be rechecked at least every 3 months. If
deSIred. stability checks may be
performed on an instrument othet' than
that initially used for the attenuator
calibration (Section 3.4). However. if a
d,ffe Dt instrument is u~ed. the
instl lent shall be a high quality
labore ory tranSmL510meter or
spectn photometer and the same
Instrument shall always be used for the
stability checks. If a secondary
Instrument IS to be used for stability
checks. Ihe value of the calibrated
altenuator shall be measured on this
secondary Instrument immediately
following calibration and prior to being
used. If over a period time an attenuator
Equation 1-1
value chanses by more than :t:2 percent
opacity. it shall be recalibrated or
replac.d by a new attenuator.
If this procedure is conducted by the
filter or screen manufacturer or
independent laboratory. obtiin a
statement certifying the valu!!s and tbat
the specified procedure. or equivalent,
was used.
8.1.4 Calibration Error TeaL wert
the calibrated attenuators (low, mid. and
high ranse) in the transmissometer pa th
at or as near to the midpoint as feasible.
The attenuator must be placed in the
measurement path at a poinfwhere the
effluent will be measured: i.e.. do not
place the calibrated attenuator in the
instrument housing. While inserting the
attenuator. assure that the entire
projected beam will pass throug!) the
attenuator and that the attenuator is
inserted in a manner which minimizes
interference from reflected light. Make a
total of five nonconsecutive readings for
each filter. Record tile monitoring
system output readings in percent
opacity (see example Figure 1-1).
8.1.5 System Response Test. Insert
the high-range calibrated attenuator in
the transmissometer path five times and
record the time required for the system
to respond to 95 percent of final zero
aDd high-range filter values (see
example Figure 1-2).
8.2 Preliminary Field Adjustments.
Install the continuous monitoring system
on the affected facility according to the
manufacturer's written instructions and
perform the following prehminary
adjustments:
8.2.1 Optical and Zero Alignment.
When the facility is not in operation.
conduct the optical alignment by
aligning the light beam from the
transmissometer upon the optical
surface located across the duct or stack
ILe.. the re\roflector or photodetector. aa
applicable) in accordance with the
manufacturer's IlIs\ructions. Under clear
stack conditions. verily the zero
alignment (performed in Section 8.1.1)
by assuring that the monitoring system
response for the simulated zero check
coincides with the actual zero measured
by the transmissometer across the clear
stack. Adjust the zero alignment. if
necessary. Then. after the affected
facility has been started up and the
effluent stream reaches normal
operatil18 temperature. reclteck the
optical alignment. If the optical
alignment has shifted realign the optics.
8.2.2 Optical and Zero Alignment
(Altemative Procedure). If the facility is
already on line and a zero stack
condition cannol practicably be
obtained. use the zero alignment
obtained during the preliminary
adjustments (Section 8.1.1) prior to
158
installation of the transmissometer on
the stack. After completing all the
preliminary' adjustments and tests
required in Section 8.1. install the
system at the SOUTee and align the
optics, i.e.. align the light beam from the
trarumissometer upon the optical
surface located across the duct or stack
in accordance with the manufacturer's
instruction. The zero alignment
conducted in this manner shall be
verified and adjusted. if necellary. the
first time the facility is not in operation
after the operational test period has
bet:n completed.
8.3 Conditioning Period. After
completing the preliminary field
adjuatmenta (Section 8.2). operate the
sy~em accordin8 to the manufacturer's
instructions £.or an initial conditioning
period of not less than 168 hours while
the source is operating. Except during
times of instrwnent zero and upscale
calibration checks. the continuous
monitoring system will analyze the
effluent gas for opacity and produce a
permanent record of tbe CODtinuouS
monitoring system output. During this
conditioning period. there shall be no
unscbeduled maintenance. repair. or
adjustment. Conduct daily zero
calibration and upscale calibration
checks. and. when accumulated drift
exceeds the daily operating limits, make
adjustments and/or clean the exposed
optical surfaces. The data recorder shall
reflect these checks and adjustments. At
the end of the operational test period.
verify that the instrument optical
alignment is correct. If the conditioning
period is interrupted because of source
breakdown (record the dates and times
of process shutdown), continue the 168-
hour period following resumption of
source operation. If the conditioning
period i. interrupted because of monitor
failure. reatart the 168-hour conditioning
period when the monitor becc"ne\t
operational.
8.4 Operlltional Test Period. After
completing the conditioning period
operate the system for an additional
168-hour period. It is not nece!nlary thai
the 168-hour operational test period
immediately follow the 168-hour
conditioning period. Except during times
of instrument zero and upscale
calibration checks. the continuous
monitoring system will analyze the
emuent gas for opacity and will produce
a permanent record of the continuous
monitoring system outpw. During this
period. there will be no unscheduled
caintenance. repair. or adjustment. Zero
and calibration adjustments. optical
surface cleaning, and optical
realignment may be performed
(optional) only at 2f-hour intervals or at
-------
Federal Register I Vol. 44. No. 197 I Wednesday. October 10, 1979 I Proposed Rules
58607
such shorter intervals as the
manufacturer's written instructions
specify. Automatic zero and calibration
adjustments made by the monitoring
system without operator intervention or
initiation are followable at any time. If
the operational test period is interrupted
because of source breakdown. continue
the 1OO-hour period following
resumption of source operation. If the
test period is interrupted because of
monitor failure. restart the 168-hour
period when the monitor becomes
operational. During the operational test
period, perform the following test
procedures:
8.4.1 Zero Drift Test. At the outset of
the 168-hour operational test period.
record the initial simulated zero and
upscale opacity readings (see example
Figure 1-3). After each 24-hour interval
check and record the final zero reading
before any optional or required cIeanin~
and adjuslment. Zero and upscale
calibration adjustments, optical surface
cleaning, and optical realignment may
be performed only at 24-hour intervals
(or at such shorter intervals as the
manufacturer's written instructions
specify) but are optional. However.
adjustments and/or cleaning must be
performed when the accumulated zero
calibration or upscale calibration drift
exceeds the 24-hour drift specifications
(:t2 percent opacity). If no adjustments
are made after the zero check the final
zero reading is recorded as the initial
reading for the next 24-hour period. If
adjustments are made, the zero value
after adjustment is recorded as the
initial zero value for the next 24-hour
period. If the instrument has an
automatic zero compensation feature for
dirt accumulation on exposed lens. and
the zero value cannot be measured
before compensation is entered then
record the amount of automatic zero
compensation for the final zero reading
of each 24-hour period. (List the
indicated zero values of the monitoring
system in parenthesis.)
8.4.2 Upscale Drift Test. At each 24-
hour interval. after the zero calibration
value has been checked and any
optional or required adjustments have
been made. check and record the
simulated upscale calibration value. If
no further adjustments are made to the
calibration system at this time. the final
upscale calibration value is recorded a8
the initial upscale value for the next 24-
hour period. If an instrument span
adjustment is made. the upscale value
after adjustment is recorded as the
initial upscale for the next 24-hour
period.
During the operauonal test period
record all adjustments, realignments and
lens cleanings.
9. Calculation. Data Analysis, and
Reporting
9.1 Arithmetic Mean. Calculate the
mean of a set of data as follows:
.. 1 "
JI . n 1~1 xi
EqUltlo" 2-1
Where:
x = mean value.
n = number of data points.
1XI = algebraic sum of the individual
measurements. x.
9.2 Confidence Interval. Calculate
the 95 percent confidence interval (two-
sided) as follows:
C.t. . t.975
95 ".n:r
In (h/) - (h,-)2
EqUltlon 2-2
Where:.
C.I." = 95 percent confidence interval
estimate of the average mean value.
'.975 = '(1--<1/2).
Tabl. 1-3-' 975 ~'alues
'815 1975 " 1975
2 '2108 1 2447 '2 220'
3 .303 I 2 JI5 13 2119
. 3182 8 2308 ,. 2160
5 2111 '0 2262 15 2105
I 251' " 2221 18 213'
The values in this table are already
corrected for n-1 degrees of Freedom.
Use n equal to the number of data
points.
9.3 Conversion of Opacity Values
from Monitor Path length to Emission
Outlet Pathlength. When the monitor
pathlength is different than the emisson
outlet pathlength, use either'of the
following equations to convert from one
basis to the other (this conversion may
be automatically calculated by the
monitoring system):
log(1-0p.)=(L./L,) Log (1-0p,) Equation 1-4
D.=(L./L.) Equation 1-5
Where:
Op.=opacity of the effluent based upon L,
Op.=opacity of the effluent based upon L.
L. = monitor pathlength
L.=emission outlet pathlength
D,=optical density of the effluent baled
upon L,
D.=optical density of the effleunt based
upon L.
9.4 Spectral Response. Using the
spectral data obtained in Section 6.1.
develop the effective spectral response
curve of the transmissometer. Then
determine and report the peak spectral
response wavelength. the mean spectral
159
response wavelength. and the maximum
response at any wavelength below 400
nm and above 700 nm expressed as a
percentage of the peak response.
9.5 Angle of View. For the horizontal
and vertical directions, using the da ta
obtained in Section 6.2. calculate the
response of the receiver as a function of
viewing angle (21 centimeters of arc
with a radius of 3 meters equal 4
degrees), report relative angle of view
curves. and determine and report the
angle of view.
9.6 Angle of Projection. For the
horizontal and vertical directions, using
the data obtained in Section 6.3,
calculate the response of the
photoelectric detector as a function of
projection angle, report relative angle of
projection curves. and determine and
report the angle of projection.
9.7 Calibration Error. See Figure 1-1.
If the pathlength is not adjusted by the
measurement system, subtract the
actual calibrated allenuator value from
the value indicated by the measurement
system recorder for each of the 15
readings obtained pursuant to Section
6.1.4. If the pathlength is adjusted by the
measurement system subtract the "path
adjusted" calibrated attenuator values
from the values indecated by the
measurement system recorder the "path
adjusted" calibrated attenuator values
are calculated using equation 1-4 or 1-
5). Calculate the arithmetic mean
difference and the 95 percent confidence
interval of the five tests at each
attenuator value using-Equations 1-2
and 1-3. Calculate the sum of the
absolute value of the mean difference
and the 95 percent confidence interval
for each of the three test attenuators:
report these three values as the
calibra tion error.
9.6 Zero and Upscale Calibration
Drifts. Using the data obtained in
Sections 8.4.1 and 8.4.2 calculate the
zero and upscale calibration drifts. Then
calculate the arithmetic means and the
95 percent confidence intervals using
Equation81-2 and 1-3. Calculate the
sum of the absolute value of the mean
and the 95 percent confidence interval
and report the"se values as the 24-hour
zero drift and the 24-hour calibration
drift.
9.9 Response Time. Using the data
collected in Section 8.1.5. calculate the
mean time of the 10 upscale and
downscale tests and report this value as
the system response time.
9.10 Reporting. Report the following
(summarize in tabular form where
appropriate).
9.10.1 General Information.
a. Instrument Manufacturer.
b.Instrument Model Number.
c. Instrument Serial Number.
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5I6CI8
Federal Relister f VoL 44. No. 197 } Wednesday. Odobe!" 10. 1179 } ProptJsed Rules
d. Pf!rsoats~ respoasibU! for
aprrallofral and corrclitianing test
periods and affiJ,jatiol1.
e. Facrbty bemgl'llOnitored.
f. Schematic wlUoniloring 8~telD
measurement path locatian.
/!- MOIIitor p8thleaglh. rueters.
It. EmlS8IOIlo outlH patblengllt.. meteR.
i. System spall valll~. perceftt opacity.
j. Upscale- ca}ibraUan ¥awe-. pelCftI(
OpaCity.
IL Calibrated AUeftltalClr Yltlll~ flew,
mid. and high range), perc~ Gpacity.
9 ~2 Desi8n Specifil:aLiaft Test
H.esulls
a. Peak. spectr~ r~pclnse.. om.
b. Mean spedra1 11!.5JI1l1lse-. run.
e. IUsponse a.biINl!' 700 nIDI percent of
pe,;II~.
Ii Respoou. Dejow 400 11m. pett&A& al
peak.
e. TiitallUl8le 01 view. depees.
f. Tatal angle ol pl'ujeclioa. dqrees.
9.1a..J. Operational Test Perm
ReslIlts..
a.. Calibralioa error. hip-ranae.
percell! opacity.
b. Calibratioa. error. JnickBIIgll.
percent opacity.
c. CalilxatiQa erroo.low-raAp.
percent opacity.
d. Response tim.e.. secands..
e. 24.how :teIO dnfl percent opacity.
r. 24.hour cahhratioD. dn!t. percent
opacity.
g. Lens cI.eaAi.na.. cIock. time.
h. Optical aIigAment adjustment... clock
time.
9.10.4 State18en11. Prol/ide a
staterneat that the conditiOllillg and
operational test perioda were completed
according to the requirements or
Se~ons 8.3 &.lid 8A. In this statement.
include the time period. during wbU:h
the conditioning and operational wt
periods wer~ coruiu.c.~d.
9.10.s Appendix. Provide. the data.
tabulations and calQlla.tiou wr lha
alleve tabulated results-
9.11 Retest. U the CQQtilUllOUS
morutorill3 sys.tem operates withia. the
specWed performan!:e parar1letan. of
Table 1-1. the operatio.altut pe!'1Od
will be successfuOy concluded. 1£ th~
canUnIWus mODitoring sys~m £ails. tD
meet allY oC the spe£if1ed per(oclUana
parameters. repeat the operational l.eu
per' ~ with a s)lstem that me~ts th.
de~ 11 specificatiou and is expuaa to
met' he performance speci£ica.li.oDa.
1& Bib~.
10.1 "ExpetilDftl.tm Statistics:'
Department of Commerc~. National
Bureau of Standards Handbook 91. 1963,
pp. 3-31. paragraph. :J-3.T.4.
10.2 "Performance Speciliarionl (or
Stat~-&auce Manitorila1J SyI~"S
for Gans aaG Vilible Emiuion..."
Environmental Protection Agency.
Research Triangle Park. N. C" EPA~I
2-7~3, January 1974.
IIWNQ COOl --.o1-t1
160
-------
Federal Register I Vol. 44, No. 197 I Wednesday, October 10, 1979 I Proposed Rules
58609
Pe~o~ Conducting Test Analyzer Manufacturer
Affil iation Model/Serial No.
Date - Location
Monitor Path length. L, Emission Outlet Pathlength. L2
Monitoring System Output Pathlength Corrected? Yes_No-
Calibrated Neutral Density Filter Values
Actual Optical Density (Opacity): Path Adjusted Optical Density (opacity)
Low Range_( ) Low Range (-)
Mid Range_(_) Mid Range (-!
High Range_( ) High Range ( )
Run Calibration Filter Instrument Reading Arithmetic Difference
Number Value (Percent Opacity) (% Opacity)
(Path Adjusted Percent Opacity) Low Mid High
1 - Low - -
2-Mid - -
3 - High - -
4 - Low - -
5-Mid - -
6 - High - -
7 -. Low - -
a-Mid - -
9 - High - -
10-Low - -
11-Mid - -
12-High - -
13-Low - -
14-Mid - -
15-High - - -
X :><: X
Arithmetic Mean (Equation 1 - 2); A
Confidence Interval (Equation 1 - 3): B
Calibration Error IAI + IBI
Figure 1 - 1. Calibration error determination
161
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58610
Fed.a1 R81i*r I Vol. 44. No. 191 J Wednesday. Odob. 10. lW19 I ProP9Rd Rules
, Person Conducting Test Analyzer Manufacturer
A ffi I iation Model/Serial No.
Date LDcalion
High Range Calibration Filter Value: Actual Optical Density lOpacit,,~ , ---.
Pa~ Adjusted Optical Densiw .QJ)acj,~) r )
Upscale Response VaLue ( 0.95 x filtllfllitlcie) percent opacity
OowJ1SCM R~ Vakae 'Q.OQ ~ tutu 1IakI&~ pelcent opadt'JI
Upscale 1 seconds
2 second$
3 sec:ood&
.. seconds
5 seconds
Downscale 1 seconds
2 seconds
3 seconds
4 seconds
5 seconds
Alteeage response seconds
Figur~ ~.2. Respo~ Ti~ Dererminatron
162
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Federal Register I Vol. 44, No. 197 I Wednesday, October 10, 1979 I Proposed Rules
58611
Person Conducting Test Analyzer Manufacturer
Affiliation Modell Serial No.
Date Location
Monitor Pathlength, L, Emission Outlet Path length, L2
Monitoring System Output Path length Corrected:? Yes- No-
Upscale Calibration Value: Actual Optical Density (Opacity) (-)
Path Adjusted Optical Density (Opacity) ( )
Percent Opacity Align-
ment
.... ....
"tI Cali- "tI ,....
AI J!! "tI
...
Zero en Upscale Calibration Upscale bration en AI
:I :I C .... ,....
Date Time Zero Reading- Drift :C Reading Drift Drift :c '" "tI '0
AI AI J!!
'" '" c:; ~ '"
Initial Final e Initial Final c en U :I
'" C AI :c
Begin End A B C = B-A AI D E F = E-D G = F-C" a. ~ .s::
N en U '"
Arithmetic Mean (Eq. 1-2)
Confidence Interval (Eq. 1-3)
Zero Drift Calibration Drift
.without automatic zero compensation
"if zero was adjusted (manually or automatically)
prior to upscale check, then use c = 0 .
8IWIIQ COCIII5IOo01.c
Figure 1 .3. Zero Calibration Drift Determination
163
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58612
Federal Register I Vol 44. N~ 197 , Wednesday. October 10; 1979' I Ptopased Rules
Perfor= SpecIfication 2-
Specd/cations and Test Procedures for
SO, and NO. Continuous Monrtoring
Systems in Stationary Sources
1. Applicability and Principle
t.1 Applicability. This Specification
contains (a] installation requirements.
[bl Instrument performance and
equipment specifications. and (c) test
procedures and data reduction
procedures for evaluating the
acceptability of SO, and NO, cO'lTt'imrous
mOl1ltonng systems. which may include.
for cerlal!) stalionary 5OIIrces. WlueA1
monitors. The test procedures in item
[c). above. are not applicable to single.
pass. in-Situ continuous monitoring
systems; these systEms will be
evaluated on a ca.se-by-case basis upon
written request to the Administrawr and
alternative test procedJJres will be
Issued separa!ely.
t.~ Principle. An,. SO, or NO.
contll1tJous Iftorrironng sysrem tlta.\ is
expected to meet this Specificafion is
Installed, calibrated. and operated for a
specIfied length of time'. Daring tlm
specified time period. the continuous
mot1llonng system is eval.ua.ted. ta
determine confurmance with the
SpecIficatIOn.
2. Definitions
Z,1 Continuous Monitoring System.
Th. total equipment required for the
dpt""m'Mllion of a 8as COO£efI\raIiOD OP
a RaS emiSSion r.ate-. The system consists
of the fallowing major sub-systems:
2.1.1 Sample Interface. That portion
of a system thaI is Dsed for one or morE'
of the following: sample acquisition.
sample transportation. sample
condilloning. or protection or the
monitor from the effects of the stack
e fIT U"E'1rt.
~ 1~. Pollutant Analyzer. That
pOMIO<'\ of the system thaL ien.se~ ~
4IoUutant gas and generates an output
that is proportionat to the g8S
concentration.
lo1 3. Diluent Analyzer (if
applicable). That portion of the ~m
that senses the diluent gas (e.g.. CO. or
0,) ard generates an autput ttrat ~
prop, -llOnal to the gas concentration.
z'1 Data Recorder. That portion of
the- m lltonng system thaI prO¥ide~ a
perma! ent record of the analyzer
output The data recorder may include
autolr.allc data reduction capabilities.
~~ Types of Monitors. Continuous
mUllItors are categonzed as "extractive'
l1r "m-sltu." which are further
cdtps.:"nzed as "point." "multipoint,"
"limited-path." and "path" type
monitors or as "single-pass" or "double-
pass" type monitors.
2.2.1 Extractive Monitor. One that
withdraws a gas sample from the stack
and tr.msports the sltmpfeo t& the-
analyzer.
2.2.2 Tn-situ Moniror. One that
lenses. tJ. gas CGBcentration in the
stack environment and does not extract
a sampre for anarysis.
:z..z.a Point MQnitor. One that
measures the gas concentration either at
a Iirlgle point or .Iong . path wltich is
less than 10 percent of the length of a
spef:jfied Iftusuremen r line-.
2.2.4 Multipoint MQnitor. One that
measures the gas concentration at Z or
more points.
2.2.5 Limited-Patll Mcmi1ar. One that
me;r~ th~ g'II1f CO'l..".. b a tiu* .Iong .
path. which is 10 to 90 percent of the
lensth of a specified measurement line.
2.2.6 Path Monitor. One that
:neas~ th~ gas concentratioD along a
path. which is greater than 90 percent of
the length of a speci.!ied messUJ'ement
line.
z..z.:z Sin3l&-Pua Manitar. One that.
has the transmitter and tl12 detector on
opposite sides of the stack or duct.
2.2.6 Double-Pass Monitor. One that
has the transmitter and the detector on
the same side of the stack or duct.
2.3 Span Value. The upper limit of a
ges £OfM:entration measuremenl range
which is specified for affected source
categories in the applicable subpart of
the regulations.
2.4 Calibration Gases. A known
coocentration ofa gas in an appropriate
diluent gas.
2.!t Calibration Gn Cells Of' FHters.
A clevice which. when inserted between
the tr8IJSoultel and. de.1ector of !he
analyzer. prodJJces the desired output
level on the data recorder-.
Z,6 Relative Accuracy. The degree of
cor.-ectness including analytical
variations of the gas concentration or
emission rate determined by the
CUI,I",uOu~ nronitoring ~tem. relaliTlr
to the value determined by the reference
method{~~
2.7 Calibration Error. The difference
between the g89 concentration indicated
by the continuous monitoring system
and the known concentration of the
calibration gas. gas cell. 01' filter.
2.8 Zero Drift. The difference in the
continuous monitoring system output
readings before and after ~ stated pet'iod
of operation during which no
unscheduled maintenance. repair. or
adjustment took place and when the
pollutant1:oncentration at the- time of
the measurements was zero (Le" zero
gas. or zero gas cell or filter).
2.9 Calibration Drift. The difference
in the continuous monitoring system
output reeding~ before- and after a ~tated
period of operation during which no
164
unscheduled maintenance. repair or
adjustment took prace and when the
poJlYtltRt concentration aot the lime of
the measurements was a high-level
vatue (i.e.. calibration gas. gas cell or
filter).
2.10 Response Time. The amount of
time it takes rhe conrinuous monitoring
system to display 011 the liala re~order
95 percent of a step change iit pollutant
C'CIIIC.ee atioo..
2.11 Conditioning Period. A
minimllm period of tirtreo owr which the
cantinuous monitoring system is
expected to operate with no
unscheduled maintenance. repair. or
adjustments prior to initiation of the
operational test period.
2.12 Operational Test Period. A
minimum period of time over which the
continuous monitoring system is
expected to operate within the
established perlw:mance speci£ica tions
with no unscheduled maintenance.
repair or-adjustment.
3. Installation Specifications
WtaIl the contil1UOlIJO monitoring
system at a location where the pollutant
concentration measurements are
representative of the total emissions
from the affected facility and are
representative ofthe concentration over
the cross section. Both requirements can
b~ me't as follows:-
3.1 Measurement LocatioJl. Select an
accessible lllaa5uremellt location ill the
stack or ductwork that is atleast2
equivalent diameters downstream from
the nearest control device' or other point
at which a change in the pollutant
concentration may occur and at least 0.5
equivalelllt diameters upstream from the
effluent 1!X1nnrst. lndmd1ral SUbpartif of
the regulations may contain additional
reqYirell\8nls. For exampl.e. (or steam
generating facilities~the location must
be downstream of the air preheater.
3.2 Measurement Points or Paths.
There are two alternatives. The tester
may choClse either (a) to conduct the
stratification check procedure given in
Se£tKm 3.3 t& seled the po.nt. points. or-
path of avtn'age ga.s.cancentralion o~ (bt
to use the options listed below without a
stratification dreck.
Note.-For the purpose o( thi. Mr:tiOll. the
"centroidal area" is defined as a concentric
area that is geometrically similar to the stack
cross section and is no greater than t percent
o( the slack aOMosectlonet area.
12.1 SOrand NO. PaLh Monitoring
Systems. The tester may choose to
centrally' locate tlte sample interface
(path) of the monitoring system on a
measurement line that passes through
the "centroidal area" of the cross
section.
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Federal Register I Vol. 44, No. 197 I Wednesday, October 10, 1979 I Proposed Rules
58613
3.2.2 SO. and NO. Multipoint
Monitoring Systems. Tbe tester may
choose to space 3 measurement points
along a measurement line that passes
through the "centroidal area" of the
stack cross section, 8t distances of 16.7,
50.0. and 63.3 percent of the way across
it (see Figure 2-1).
"WHO CODE I5lO-01-11
165
-------
58614
Federal Register I Vol. 44. No. 197 I Wednesday, October 10.1979 I Proposed Rules
l
POINT
NO.
3
2
DISTANCE
(% OF LI
1
2
3
16.7
sa.a
833
"CENTROIDAl
AREA'" ~
l
J
2
F.gur 21. Location of an example measurement line ILl and measurement points.
IllllNG 'DE 'S60-0'~
166
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Federal Register I Vol. 44, No. 197 I Wednesday, October 10. 1979 I Proposed Rules
58615
The following sampling strategies. or
equivalent. for measuring the
concentrations at the 3 points are
acceptable: (a) The use of a 3-probe or a
3-hole single probe arrangment.
provided that the sampling rate in each
of the 3 probes or holes is maintained
within 10 percent of their average rate
(This option requires a procedure.
subject to the approval of the
Administrator. to demonstrate that the
proper sampling rate is maintained); or
(bl the use oCa traversing probe
arrangement, provided that a
measurement at each point is made at
least once every 15 minutes and all 3
points are traversed and sampled for
equal lengths of time within 15 minutes.
3.2.3 SO. Single-Point and Limited-
Path Monitoring Systems. Provided that
(a) no "dissimilar" gas streams (i.e..
having greater than 10 percent
difference in pollutant concentration
from the average) are combined
upstream of the measurement location.
and (b) for steam geneldting facilities, a
CO. or O. cotinuous monitor is installed
in addition to the SO. monitor.
according to the guidelines given in
Section 3.1 or 3.2 of Performance
Specification 3. the tester may choose to
monitor SO. at a single point or over a
limited path. Locate the point in or
centrally locate the limited path over the
"centroidal area." Any other location
within the inner 50 percent of the stack
cross-sectional area that has been
demonstrated (see Section 3.4) to have a
concentration within 5 percent of the
concentration at a point within the
"centroidal area" may be used.
3.2.4 NO, Single-Point and Limited-
Path Monitoring Systems. For NO,
monitors, the tester may choose the
single-point or limited-path option
described in Section 3.2.3 only in coal-
burning steam generators (does not
include oil and gas-fired units) and nitric
acid plants. which have no dissimilar
gas streams combining upstream of the
meilsurementlocation.
3.3 Stratification Check Procedure.
Unless specifically approved in Section
3.2.. conduct a stratification check and
select the measurement point. points. or
path as follows:
3.3.1 Locate 9 sample points. as
shown in Figure 2-2. a or b. The tester
may choose to use more than 9 points.
provided that the sample points are
located in a similar fashion as in Fgure
2-2.
3.3.2 Measure at least twice the
pollutant and. if applicable (as in the
case of steam generators), CO. or O.
concentrations at each of the sample
points. Moisture need not be determined
for this step. The following methods are
acceptable for the measurements: (a)
Reference Methods 3 (grab-sample). 6 or
7 of this part: (b) appropriate
instrumental methods which give
relative responses to the pollutant (i.e..
the methods need not be absolutely
correct), subject to the approval of the
Administrator. or Ic) alternative
methods subject to the approval of the
Administrator. Express all
measurements, if applicable, in the units
of the applicable standard.
3.3.3 Calculate the mean value and
select a point, points: limited-path. or
patti which gives an equivalent value to
the mean. The point or points must be
within. and the limited-path or path
must pass through. the inner 50 percent
of the stack cross-sectional area. All
other locations must be approved by the
Administrator.
IIIWNQ CODE 15I4HI1-t1
167
-------
58616
Federal Register I Vol. 44. No. 197 I Wednesday, October 10,1979 I Proposed Rules
4
POINT
NO
DISTANCE
1% OF DI
1,9
2, 8
C
3, 7
4 6
100
300
500
700
900
3
Q
2
lal
I I
I I
I
I . 1
1 2 I
1 I
- ----,--- --1- - ---
I I
1 . I
I 5 I
, I
- --- -1-- ---1-----,
I I
I I
I . I
I 8 I
I I
.
.
3
.
.
4
6
.
.
7
9
Ibl
BILlI'''~ CODE 8510-01..(:
Figure 2.2. Location of 9 sampling pOints for stratification check.
168
',
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Federal Register I Vol. 44. No. 197 I Wednesday. October 10. 1979 I Proposed Rules
58617
3.4 Acceptability of Single Point or
Limited Path Alternative Location. Any
of the applicable measurement methods
mentioned in Section 3.3.2, above. may
be used. Measure the pollutant and. if
applicable. CO. or O. concentrations at
both the centroidal area and the
alternative locations. Moisture need not
be measured for this test. Collect a 21-
minute integrated sample or 3 grab-
samples. either at evenly spaced (7 ::t 2
min.) intervals over 21 minutes or all
within 3 minutes. at each location. Run
the comparative tests either
concurrently or within 10 minutes of
each other. Average the results of the 3
grab-samples~
Repeat the measurements until a
minimum of 3 paired measurements
spanning a minimum of 1 hour of
process operation are obtained.
Determine the average pollutant
concentrations at the centroidal area
and the alternative locations. If
applicable. convert the data in terms of
the standard for each paired set before
taking the average. The alternative
sampling location is acceptable if each
alternative location value is within :t: 10
percent of the corresponding centroidal
area value and if the average at the
alternative location is within 5 percent
of the a\l.llrage of the centroidal area.
4. Performance and Equipment
Specifications
The continuous monitoring system
performance and equipment
specifications are listed in Table 2-1. To
be considered acceptable. the
continuous monitoring system must
demonstrate compliance with these
specifications using the test procedures
of Section 6.
5. Apparatus
5.1 Continuous Monitoring System.
Use any continuous monitoring system
of SO. or NO. which is expected to meet
the specifications in Table 2-1. For
sources which are required to convert
the pollutant concentrations to other
emission units using diluent gas
measurements. the diluent gas
continuous monitor. as described in
Performance Specification 3 of this
Appendix. is considered part of the
continuous monitoring system. The data
recorder may be an analog strip chart
recorder type or other suitable device
with an input signal range compatible
with the analyzer output.
5.2 Calibration Gases. For
continuous monitoring systems that
allow the introduction of calibration
gases to the analyzer. the calibra tion
gases may be SO. in air or N.. NO in N..
and NO. in air or N.. Two or more
calibration gases may be combined in
the same gas cylinder. except do not
combine the NO and air. For NO.
monitoring systems that oxidize NO to
NO.. the calibration gases must be in the
form of NO. Use three calibration gas
mixtures as specified below:
5.2.1 High-Level Gas. A gas
concentration that is equivalent to 80 to
90 percent of the span value.
T81148 2-1.-Contmuous Momtonng SystBm
PtNformance and Equipment SpgclficlJtlOns
Parameter
;;0 168 hour..
Speo'ocabon
t. Cond'bon.ng
penod '.
Z. 01*1- ,..I
penod '.
3. CUbrluan 8n'Ot .. .
I. R_.. --....
5 Zero dntt (2.
hour) II...
8. Zero ct1ft (24-
hour)..f.
1. C_"1ion dntt
(2 =....., '.
8. CaJobfllion dntt
(2I-hour) '.
8. Rill'"
8CCW8Cy ",
10. Cllobfluan go
C861s 01 fillers.
11 0.18 recora.
cP\8rt retOtubOn.
12 ExtrIC-
Irstemt Wtth dfIu8nt
morwtOfI.
"168 hours.
.. 5 pel aI 88th mtd-level Ind high-
1....81 calibration value.
~ 15 mlnut88 (S m.nut8!l for 3-~
trav....-.g pl'oM 8/fangetnenU.
IIIIi 2 pet at span value.
.. 2 pel 0' ""an vllue.
IIIIi 2 pel of span value.
"25 pel 0'- vllue.
IIIIi 20 pet of tM mea" 'llve of
,.terence method(s, ,." dill In
term, 01 8rT14SS1On standard or 10
percem oflhe appl.cable
standard. wn.ch8V. II gr.ll.
MUll prQYtde . check of 1M a"alyzer
inlemall.nlI.TQt.1 anet len581 and aU
eJectrOntC Clf'CUttry Includtng the
radiatIOn source and deleclOf'
assembly whICh Ire normaity uN
In IImphng 100 anllySiI
Chart sealet musl be readable.to
Wlthtn.. 050 pet of full.sul.
Must use the same sampte Interface
10 IImple bolh the pollutant and
diluent gases Ptae. In senet
(dlluenl 8"" poUullnl analyzer) Of
use . "T "8 Ounng the
CondltJOrllng and operallonal fest
penods. 1h8 continuous mot'Mtonng
'Yslem shall not r8qUwe any
cooeclNe m..nlenance. rep.".
replacemenf. or adruSln'I8nt 01t\8'
than that CieaMy specified aa
roullne Ind r8QUlred 11"1 1"-
operation and maintenance
manuals' e.pressed as the sum
at the absolute mean value ptua
lI1e 95 percent conlKlence Inlerval
of a sene of lests dIVIded by .
reference value' A 6ow.lev81 15-
15 percenl 01 span value) dnft test
may be subslliuted fer the Z8fO
Dflft teslS.
5.2.2 Mid-Level Gas. A gas
concentration that is equivalr.nt to 45 to
55 percent of the span value.
169
5.2.3 Zero Gas. A gas concentralion
of less than 0.25 percent of the span
value. Ambient air may be used for the
zero gas.
5.3 Calibration Gas Cells or Fillers.
For continuous monitoring systems
which use calibration gas cells or fillers.
use three certified calibration gas cells
or filters as specified below:
5.3.1 High-Level Gas Cell or Filler.
One that produces an output equivalent
to 80 to 90 percent of the span value.
5.3.2 Mid-Level Gas Cell or Filter.
One that produces an output equivalent
to 45 to 55 percent of the span value.
5.3.3 Zero Gas Cell or Filler. One
that produces an output equivalent 10
zero. Alternatively. an analyzer m~y
produce a zero value check by
mechanical means. such as a movable
mirror.
5.4 Calibration Gas-Gas Cell or
Filter Combination. Combinations of the
above may be used.
6. Performance Specification Test
Procedures.
6.1 Pretest Preparation.
6.1.1 Calibration Gas Certification.
The tester may select one of the
following allernatives: (a) The tester
may use calibra tion gases prepared
according to the protocol defined in
Citation 10.5. i.e. These gases may be
used as received without reference
method analysis (obtain a statement
from the gas cylinder supplier certifying
that the calibration gases have been
prepared according to the protocol): or
(b] the tester may use calibration gases
not prepared according to the protocol.
In case [b). he must perform triplicate
analyses of each calibration gas (mld-
level and high. level. only) within 2
weeks prior to the operational test
period using the appropriate reference
methods. Acceptable procedures are
described in Citations 10.6 and 10.7.
Record the resulls on a da ta sheet
(example is shown in Figure 2,..3). Edch
of the individual analytical resulls must
be within 10 percent (or 15 ppm.
whichever is greater) of the average:
otherwise. discard the entire set and
repeat the triplicate analyses. If the
average of the triplicate reference
method test results is within 5 percent of
the calibration gas manufacturer's tag
value. use the tag value: otherwise.
conduct at least 3 additional reference
method test analyses until the resulls of
6 individual runs (the 3 original plus 3
additional] agree within 10 percent ur 15
ppm. whichever is greater. of the
average. Then use this average for the
cylinder value.
-------
58618
Federal Register I Vol. 44. No. 197 I Wednesday, October 10. 1979 I Proposed Rules
Figure 2-3.
Analysis of Calibration Gases&
Date
(Must be within 2 weeks prior to the
operational test period)
Reference Method Used
----
Sample Run
-Mid-levelb-
ppm
------
-----
------
2
3
-----
-----
High-levelc
_--FE!!
-------
-------
-----
----
verage
aximum % Deviationd
-----
------
---
a Not necessary if the protocol in Citation 10.5 is used
to prepare the gas cylinders.
b
Average ~st be 45 to 55 percent of span value.
c
Average must De 80 to 90 percent of span value.
d
Must be < + 10 percent of applicable average or
whichever Ts greater.
6.1.2 Calibration Gas Cell or Filter
Certification. Obtain (a) a statement
from the manufacturer certifying that the
calibration gas cells or filters (zero, mid.
level. and high-level) will produce the
sidled Instrument responses for the
continuous mOnitoring system, and (b) a
description of the test procedure and
equipment used to calibrate the cells or
filters. At a minimum, the manufacturer
must have calibrated the gas cells or
filters against a simulated source of
"nown concentration.
15 ppm,
6.2 Conditioning Period. Prepare the
mOnitoring system for operation
according to the manufacturer's written
instructions. At the outset of the
conditioning period, zero and span the
system. Use the mid-level calibration
gas (or gas cell or filter) to set the span
at 50 percent of recorder full-scale. If
necessary to determine negative zero
drift. offset the scale by 10 percent. (Do
not forget to account for this when using
the calibration curve.) If a zero offset is
not possible or is impractical. a'low-
level drift may be substituted for the
170
zero drift. by u.inB a low-level (5 to 15
percent of span value) calibration g88
(or Bas cell or filter). This low-level
calibration gas (or gas ceU or filter) need
not be certified. Operate the continuou.
monitoring system for an initial 168-hour
period in the manner specified by the
manufacturer. Except during times of
instroment zero. calibration checks. and
system backpurges. the continuous
monitoring system shall collect and
condition the emuent gas sample (if
applicable). analyze the .ample for the
appropriate gal constituent.. and
produce a permanent record of the
system output. Conduct daily zero and
mid-level calibration checks and, when
drift exceeds the daily operating limils.
make adjusbnents. The data recorder
shall reflect these checks and
adjusbnent.. Keep a record of any
instrument failure during thi. time. If the
conditioning period is interrupted
because of source breakdown (record
the dates and times of process
shutdown). continue the 168-hour period
following resumption of source
operation. If the conditionlll8 period is
interrupted because of monitor failure.
restart the 168-hour conditioninB period
when the monitor becomes functional.
6.3 Operational Test Period. Operate
the continuous monitoring system for an
additional 168-hour period. The
continuous monitoring system shall
monitor the effluent. except during
periods when the sy.tem calibration and
response time are checked or during
system backpurges: however. the system
shall produce a permanent record of all
operations. Record any system failure
during this time on the data recorder
output sheet.
It is not necessary that the 168-hour
operational test period immediately
follow the 168-hour conditioning period.
During the operational test period,
perform the following test procedures:
6.3.1 Calibration Error
Determination. Make a total of 15
nonconsecutive zero. mid-level. and
high-level measurements (e.8.. zero. mid.
level, zero. high-level. mid-range. etc.).
-------
Federal Register I Vol. 44. No. 197 I Wednesday. October 10. 1979 I Proposed Rules
58619
This will result in a set of 5 each of zero.
mid-level, and high-level measurements.
Clinvert the data output to concentration
units. if necessary. and record the
results on a data sheet (example is
shown in Figure 2-4j. Calculate the
differences between the reference
calibration gas concentrations and the
measurement system reading. Then
calculate the mean. confidence interval.
and calibration errors separately for the
mid-level and high-level concentratione
using Equations 2-1. 2-2. and 2-3. In
Equation 2-3. use each respective
calibration gas concentration for R.V.
IIWNG CODE 8510-01-111
171
-------
58620
Federal Regllter I Vol. 44. No. 19'1 I Wednelday. October 10. 19'19 I Propoled Rule.
Run
no.
Figure 2-4. Calibration Error Determination
Ca1 ibratTOn gas Measurement system ArHhmetic
concentrationa reading differences
:P~-- --_Pl'!!1-_-- ----~-----
A B A-B
Mid
High
-----
-----
1
2
3
4
5
6
7
8
g
10
11
12
13
14
15
------
-------
------
------
'"---
--
--------
--
----
-------
--
-----
----
----
-----
------
--
---
----
---
----
--------
-- ---
--- ---
------
------ ---
-----
---------
-----
----
------
,--------
-------
----
Arithmetic Mean (Eq. 2-1) .
---Confidence~;al (Eq. 2-2) .
Ca 1 i brat1Q;;Error (Eq:-'2:j)YI-;
---------------- ---
a Calibration Data from Section 6.1.1 or 6.1.2
Mid-level: C. ppm
High-level: D . ppm
b Use C or D as R.V. in Eq. 2-3
--
-----
Figure 2-5. Response Time
Date ----- High-level. ___ppm
[--~est Run -- -UPsC:;;--- Do~scale ---
-- ---- min. min.
- -------- ---------
1
-- ----- --- --------
t-----.,,:.,. --- --A -:---==- -:~--~~
-----
---------
System Response Time (slower of A and B) .
"WHO COOt: .5tCHl1~
min.
172
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Federal Register I Vol. 44. No. 197 I Wednesday. October 10. 1979 I Proposed Rules
58621
6.3.2 Response Time Test Procedure.
At a minimum, each response time test
shall provide a check of the entire
sample transport line (if applicable). any
sample conditioning equipment (if
applicable). the pollutant analyzer. and
the data recorder. For in-situ systems.
pl!rform the response time check by
introducing the calibration gases at the
sample interface (if applicable). or by
introducing the calibration gas cells or
filters at an appropriate location in the
pollutant analyzer. For extractive
monitors, introduce the calibration gas
at the sample probe inlet In the stack or
at the point of connection between the
rigid sample probe and the sample
transport line. If an extractive analyzer
is used to monitor the effluent from more
than one source. perform the response
time test for each sample interface.
To begin the response time test,
introduce zero gas (or zero cell or filter)
into the continuous monitor. When the
system output has stabilized. switch to
monitor the stack effluent and wait until
a "stable value" has been reached.
Record the upscale response time. Then,
introduce the high-level calib[ation gas
(or gas cell or filter). Once the system
has stabilized at the high-level
concentration, switch to monitor the
stack effluent and wait until a "stable
value" is reached. Record the downscale
rpsponse time. A "stable value" is
equivalent to a change of less than 1
pprcent of span value for 30 seconds or 5
percent of measured average
concentration for 2 minutes. Repeat the
entire procedure three times. Record the
rpsul!s of each test on a data sheet
(example is shown in Figure 2-5).
Determine the means of the upscale and
downscale response times using
Equation 2-1. Report the slower time as
the system response time.
6.3.3 Field Test for Zero Drift and
Calibration Drift. Perform the zero and
calibration drift tests for each pollutant
analyzer and data recorder in the
continuous monitoring system.
6.3.3.1 Two-hour Drift. Introduce
consecutively zero gas (or zero cell or
filter) and high-level calibra tion gas (or
gas cell or filter) at 2-hour intervals until
15 sets (before and after) of da ta are
obtained. Do not make any zero or
calibration adjustments during this time
unless otherwise prescribed by the
manufacturer. Determine and record the
amount that the output had drifted from
the recorder zero and high-level value
on a data sheet (example is shown in
Figure 2~). TI)e 2-hour periods over
which the measurements are conducted
need not be consecutive. but must not
overlap. Calculate the zero and
calibration drifts for each set. Then
calculate the mean. confidence interval.
and zero and calibration drifts (2-hour)
using Equations 2-1. 2-2. and 2-3. In
Equation 2-3, use the span value for R.V.
6.3.3.2 Twenty-Four Hour Drift. In
addition to the 2-hour drift tests, perform
a series of seven 24-hour drift tests as
follows: At the beginning of each 24-
hour period. calibrate the monitor. using
mId-level value. Then introduce the
high-level calibration gas (or gas cell or
filter) to obtain the initial reference
value. At the end of the 24-hour period.
introduce consecutively zero gas (or gas
cell or filter) and high-level calibration
gas (or gas cell or filter); do not make
any adjustments at this time. Determine
and record the amount of drift from the
recorder zero and high-level value on a
data sheet (example is shown in Figure
2-7). Calculate the zero and calibration
drifts fop each set. Then calcula te the
mean. confidence interval, and zero and
calibration dnfts (24-hour) using
Equations 2-1. 2-2. and 2-3. In Equation
2-3. use the span value for R. V.
IILUNG CODE 8564H11-11
173
-------
1'.,0 Rdg Hi-level
Dat Zero Rdq Span Cal1b.
set Tim'- 1111 t. Fin. drift Init. Fin. dr1f drift
no. Date Begin End A B C-B-A D E F=E-[ G-F-C
1
2
3
4
5
6
7
-
8
9
10
11
12
13
14
15
Arithmetic Mean (Eo. 2-11
Confidence Interval (Eo. 2-2)
Zero Drifta Calibration
....
....:J
~
a
Use Equation 2-3. with span value for R. V.
drifta
IIWNCI ~ .-.ot-C
Figure 2-6. Zero and Calibration Drift (2 hour)
Hi-level
Dat Zerc Rdy Zero f.--!~ -- Span Callb.
set Tim. Init. Fin drift Init. Fin. dri ft drift
no. Date Begin End A B (-B-A D E F=E-D G= F-(
1
2
3
4
5
6
7
Arithmetic Mean (Eq. 2-1)
Confidence -
Interval (Eq. 2-2)
Zero drift Calibration a
l-
drift
a
Use Equation 2-3. with the span value for R. V.
Figure 2-7. Zero and Calibration Drift (24-hour)
~
~
N
N
....
!.
i
,.,
l-
i
-
<
~
;
Z
!=I
...
!!i
-
~
C8
~
C8
..
a-
..
'::'=
o
n
-
o
cr
C8
..
...
p
...
~
-
;r
"
o
..
It
i
..
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10. 1979 / Proposed Rules
58623
Note.-Automatic zero and calibration
adjuslmenls made by the monitoring system
wIthout opera lor inlervention or initiation are
allowable al any lime. Manual adjustments.
however. are allowable only al 24-hour
,nlervals. unless a shorler time is specified by
Ihe manufaclurer.
6.4 System Relative Accuracy.
Unless otherwise specified in an
applicable subpart of the regulations,
the reference methods for SO.. NO..
diluent (0. or CO.), and moisture are
Reference Methods 6, 7, 3, and 4,
respectively. Moisture may be
determined along with SO. using
Method 6. See Citation 10.6. Reference
Method 4 is necessary only if moisture
content is needed to enable comparison
between the Reference Method and
monitor values. Perform the accuracy
test using the following guidelines:
6.4.1 Location of Pollutant Reference
Method Sample Points. The following
specifies the location of the Reference
Method sample points which are on the
same cross-sectional plane as the
monitor's. However, any cross-sectional
plane within 2 equivalent diameter of
straight runs may be used, by using the
projected image of the monitor on the
selected plane in the following criteria.
6.4.1.1 For point monitors. locate the
Reference Method sample point no
further than 30 cm [or 5 percent of the
equivalent diameter of the cross section,
whichever is lIiss) from the pollutant
monitor sample point.
6.4.1.2 For multipoint monitors,
locate each Reference Method sample
traverse point no further than 30 cm (or
5 percent of the equivalent diameter of
the cross section, whichever is less)
from each corresponding pollutant
monitor sample point.
6.4.1.3 For limited-path and path
monitors, locate 3 sample points on a
line parallel to the monitor path and no
further than 30 cm [or 5 percent of the
equivalent diameter of the cross section.
whichever is less) from the centerline of
the monitor path. The three points of the
Reference Method shall correspond to
points in the monitor path at 16.7, 50.0.
and 63.3 percent of the effective length
of the monitor path.
6.4.2 Location of Diluent and
Moisture Reference Method Sample
Points.
6.4.2.1 For sources which require
diluent monitors in addition to pollutant
monitors, locate each of the sample
points for the diluent Reference Method
measurements within 3 cm of the
corresponding pollutant Reference
Method sample point as defined in
Sections 6.4.1.1, 6.4.1.2, or 6.4.1.3. In
addition, locate each pair of diluent and
pollutant Reference Method sample
pomts no further than 30 cm [or 5
percent of the equivalent diameter of the
cross section. whichever is less) from
both the diluent and pollutant
contmuous monitor sample points or
paths.
6.4.2.2 If it is necessary to convert
pollutant and/or diluent monitor
concentrations to a dry basis for
comparison with the Reference data.
locate each moisture Reference Method
sample point within 3 em of the
correspondmg pollutant or diluent
Reference Method sample point as
defined in Sections 6.4.1.1, 6.4.1.2. 6.4.1.3,
or 6.4.2.1.
6.4.3 Number of Reference Method
Tests.
6.4.3.1 For NO. monitors. make a
minimum of 27 NO. Reference Method
measurements. divided into 9 sets.
6.4.3.2 For SO. monitors. make a
minimum of 9 SO, Reference Method
tests.
6.4.3.3 For diluent monitors. perform
one diluent Reference Method test for
each SO, and/ Dr NO. Reference Method
testIs).
6.4.3.4 For moisture determinations.
perform one moisture Reference Method
test for each or each set of pollutant[s)
and diluent [if applicable) Reference
Method tests.
Note.- The lesler may choose to perfonn
more than 9 sels of NO. measuremenls or
more than 9 SO, reference ",elhod diluenl. or
moislure lesls. If this option IS chosen. the
tester may. at his dIscretion. rejecl up 10 3 of
the sel or lest results. so long as the tolal
number of sel or tesl results used to
determine Ihe relallve accuracy is greater
than or equal to 9. Report all data including
rejecled dala.
6.4.4 Sampling Strategy for
Reference Method Tests. Schedule the
Reference Method tests so that they will
not be in progress when zero drift.
calibration drift. and response time data
are being taken. Within any 1-hour
period, conduct the following tests: [a)
one set. consisting of 3 individual
measurements. of NO. and/or one SO.:
(b) one diluent. if applicable: and [c) one
moisture [if needed). Whenever two or
more reference tests [pollutant. diluent.
and moisture) are conducted. the tester
may choose to run all these reference
tests within a 1-hour period. However. it
is recommended that the tests be run
concurrently or consecutively within a
4-minute interval if two reference tests
employ grab sampling techniques. Also
whenever an integrated reference test is
run together with grab sample reference
tests. it is recommended that the
integrated sample be started one-sixth
the test period before the first grab
sample is collected.
In order to properly correia te the
continuous monitoring system and
175
Reference Method data. mark the
beginning and end of each Reference
Method test period [including the exact
time of day) on the pollutant and dJluent
[if applicable) chart recordings. Use one
of the following strategies for the
Reference Method tesls:
6.4.4.1 Single Point Monitors. For
single point sampling, the tester may: (a)
take a 21-mmute integrated sample (P.g.
Method 6, Method 4. or the integrated
bag sample technique of Method 3): (bJ
take 3 grab samples (e.g. Method 7 or
the grab sample technique of Method 3).
equally spaced at 7-minute [:!:2 minI
intervals [or one-third the test penod):
or [c) take 3 grab samples over a 3-
minute test period.
6.4.4.2 Multipoint or Path Monitors.
For multipoint sampling. the tester may
either: (a) make a 21-minute integrated
sample traverse. sampling for 7 minutes
[:!:2 minI (or one-third the test period) at
each point: or (b) take grab samples at
each traverse point. scheduling the grab
samples to that they are an equal
interval (7:!:2 minutes) of time apart (or
one-third the test period).
Nole.-If Ihe number of sample points is
greater Ihan 3. make appropnate adju81ments
to Ihe mdivldual 8ampllng time inlerval.. At
limes NSPS performance test dala ma~ be
used as part of the dala base of the
continuous mOnitoring relative 8CCUrac)
tests. In Ihese cases. olher test penod8 as
specified m Ihe applicable subparts of the
regulations may be used.
6.4.5 Correlation of Reference
Method and Continuous Monitoring
System Data. Correlate the continuous
monitopng system data with the
Reference Method test data. as to the
time and duration of the Reference
Method tests. To accomplish this. first
determine from the continuous
monitoring system chart recordings, the
integrated average pollutant and dlluent
(if applicable) concentration[s) for each
Reference Method test period. Be sure to
consider system response time. Then.
compare each integrated average
concentration against the corresponding
average concentration obtained by the
Reference Method: use the following
guidelines to make these comparisons:
6.4.5.1 If the Reference Method IS an
integrated sampling technique (e.g..
Method 6), make a direct comparison of
the Reference Method results and the
continuous monitoring system integrated
average concentration.
6.4.5.2 If the Reference Method is a
grab-sampling technique (e.g" Melhod
7), first average Ihe resdts from all grab-
samples taken dunng the test penod.
and then compare this average value
against the integrated value obtained
from the continuous monitoring system
chart recording
-------
Federal Register I Vol. 44. No. 197 I Wednesday. October 10. 1979 I Proposed Rules
58624
6.5 Data Summary For Relative
Accuracy Teats. Summarize the results
on a data sheet: example IS shown in
Figure 2~. Calculate the arithmetic
diFferences between the reference
method and the contmuous momtoring
output sets. Then calculate the mean.
confidence interval. and system relative
accuracy. using Equation 2-1. 2-2. and
2-3. In Equation 2-3. uae the average of
the reference method test results For
RV.
7. Equations
7.1 Arithmetic Mean. Calculate the
mean of a data set as follows:
. , 0
I . - r .
n t.1 '
[OUlttoo 1-2
Where:
'" ~ artthmetic mean.
n - number of data point..
~" ~Hl8cbralt lum of the IndividuHI
value,. XI'
When the mean o~the dIfferences of
pairs of data is calculated. be sure to
correct the data for moisture.
7.2 Confidence Interval. Calculate
the q5 percent confidence interval (two-
sided) as follows:
C! ..~ll
. Q~ ~ n ~. ,
",1'1-=1"
(h,)1
(ouot1"" 1-]
Where:
C I "=95 percent confidence Interval
esllmate of mean value.
t ... = 1,,-, ,,' (.ee Table 2-2)
SllUNG COO£ 'SIO-OI.11
rlbll 2-2.-1. Value.
---- ---~-
'915 '" '975 '" '915
12708 1 2U7 12 2201
4 JOJ 8 2365 13 2179
3182 . 2308 .. 2'1!O
2778 '0 2262 '5 2145
257' " 2228 '8 ~'JI
. "'~ <,tun... \'1'1., fib" Ire alreldy correct.., 'Of' n-1 ..
Q'~. 01 'r98dQm Use ft ~ 10 the nlJfTlbel' of 1OdMdu8
ItliluOS
176
-------
-
-:J
-:J
---
SOL NO b a S02a NO a
'v C02_~- 'v
Run Date and DM I M -miff DM I M -'lniH DU I U DU J M InHf' 12M J M I nHf'
~ time 'oomo oomo ",0 Sa mas~LGCY- massLG~L__-
1
-
2
--
3
--
4
-
5
-
6
1
--
8
- -- ---
9
-
10
11
---- ----- - --- --
12
II..verage
--
Confidence Interval
---
AccuracyC
------ - b
a c
For steam generators Average of 3 samples Use average of reference method
d Make sure that RM and M data are on a consistent basis. either wet or dry
F1gure 2-8. Relative accuracy determination
test results for R.V.
BilliNG CODE esiO-G'-C
l
III
!.
'"
t.
S'
..
-
<
~
~
Z
P
....
(Q
.....
-
:E
II>
Et
II>
CD
P.
II>
':C
o
n
o
0"
II>
...
....
9
....
(Q
.....
(Q
4'
o
"C
o
CD
II>
P.
~
"
to
CD
VI
~
N
VI
-------
58626
Federal Register / Vol. 44. No. 197 / Wednesday. October 10. 1979 I Proposed Rules
Ixl;lc.1.951
R.A. . ~V~-
73 Rp.latlve Accuracy. Calculate the relative accuracy of a set of data as
(1)1[I,w5:
. 100 Equation Z-3
lot-ere:
P. A.
. relati-e accuracy
absolute value of the adtt-onetlc mean
I C . I. 951
(fro," [quat1on 2-1).
. absolute valoe of the 95 percent cOllfl-
R. V.
dence interval (frOl8 [quatfon 2-2).
. reference value. as defined in SectIons
6.3.1.6.3.3.1.6.3.3.2. and 6.5.
8 Reporting
..\1 a minimum (check "Ith regional
offl' ,'s for additional requirements. U
,In Ii I summanze the following results In
t..I;"IM form: calibration error for mld-
Ipnl and high-level concentrations. the
slo"pr of the upscale and downscale
rl'sponse times. the 2-hour and 24-hour
zero and calibration dnfts. and the
'Ii"..m relative accuraC\ In addition.
p'rm ,de. for the condltl(jnln~ and
operatIOnal lest periods. a statement to
the effect that the continuous mOnitoring
svslo'm operated continuously for a
n1lnlmum of 168 hours each. except
dunn~ times of IPstrument zero.
calibration ched" s~stem backpurges
and "Jurce breakdown. and that no
curn"cllve maintenance. repair.
rep!.".ement. or adlu,tment other than
that dearly specified as routine and
required In the operation and
mall:lenance manuals were made. Also
Include the manufacturer's cerlificatiOn
statementllf applicable) for the
Cdlibratlon gas. gas cells. or filters.
Include all data sheets and calculations
and charts (data outputs I. which are
necessary to substantiate that the
Sl! sh'rn met the performance
opeClflcdtlons.
9 Rt'h'ot
If :~I' continuous monitoring system
OPI'" ,!es within the specified
pl'r! mance parameters of Table 2-1.
the ",..lIonal test period will be
sue" ,fully concluded. If the
con:,n 10US monitoring system fads to
"",,'1 dny of the specifications. repeat
that ;JUrtion Gf the testing which IS
rplaled to the faded specification.
10. [J,bllograph\
10 1 '\Ionltoring Instrumentation for
'I,P \h',lsurement oi Sulfur DI"""de In
Stationary Source emissions,"
Environmental Protection Agency.
Research Triangle Par"- N.c.. February
1973.
10.2 "Instrumentation for the
Detennination of Nitrogen Oxides
Content of Stationary Source
Emissions," Environmental Protection
Agency. Research Triangle Park, N.C..
Volume 1. APTD~847, October 1971;
Volume 2. APTD~2. January 1972.
10.3 "Experimental Statistics."
Department of Commerce. Handbook. 91.
1963. pp. 3-31. paragraphs 3-3.1.4.
104 "Performance Specifications for
Stationary-Source Monitoring Systems
for Gases and Visible Emissions."
Emmonmental Protection Agency.
Research TrIangle Park. N.C.. EPA~501
2-7~13. JanUilry 1974.
10.5 Trac
-------
Federal Register I Vol. 44. No. 197 I Wednesday. October 10. 1979 I Proposed Rules
58627
,"~Ialled al a different location from Ihat
of Ihe pollutant monitor. provided that
the diluent gas concentrations at both
localtons differ by no more than 5
percent from that of the pollutant
monitor location for CO. or the quantity.
20.9-percent 0.. for 0.. See Section 3.4
of Performance Specification 2 for the
demonstration procedure.
4. Continuous Monitor Performance and
Equipment Specifications
The continuous monitor performance
and equipment specifications are listed
in Table 3-1. To be considered
acceptable. the continuous monitor must
demonstrate compliance with these
specifications. using the test procedures
in Section 6.
5. Apparatus
5.1 CO. or O. Continuous Monitor.
Use any continuous monitor. which is
expected to meet this Specification. The
data recorder may either be an analog
strip-chart recorder or other suitable
device having an input voltage range
compatible with the analyzer output.
5.2 Calibration Gases. Diluent gases
shall be air or N. for CO. mixtures. and
shall be N. for O. mixtures. Use three
calibration gases as specified below:
BlUING CODE '~I-M
179
-------
58628
Federal -.181 I Vol. 44. No. 191 I Wednesday. October 10. 1919 I Propoeed Rule.
GEOMETRICALL Y
SIMILAR
AREA
( 1"1. OF STACK
CROSS-SECTION I
lal
GEOMETRICALL Y
SIMILAR
AREA
I ~ 1"'. OF STACK
CROSS-SECTION)
Ibl
FI(~Hl 3.1. Relative locations of pollutant (PI and diluent (DI measurement points in (al circular
and (bl rectangular ducts. P IS located at the centroid 01 the geometrically similar
area. Note: The geometrically Similar area need not be concentric.
180
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Federal R.t8l' I Vol. 44, No. 197 I Wednesday, October 10, 1979 I Proposed Rules
58629
GEOMETRICALL Y
SIMILAR
AREAS
C<1%OFSTACK
CROSS-SECTION I
GEOMETRICALL Y
SIMILAR
AREAS
I <;;1% OF STACK
CROSS-SECTION)
Figure 3.2.
PARALLEL
MEASUREMENT
LINES
lal
PARALLEL
MEASUREMENT
LINES
o
P
I I
I I
I I
I I
I I
(bl
Relative locations of pollutant (PI and diluent (DI measurement paths for (al circular
and (bl rectangular ducts. P is located at the centroid of both the geometrically Slml'
lar areas and the pollutant monitor path cross.sectlonal areas. D is located at the cen.
troid of the diluent monitor path cross.sectlOnal area.
BIWHO CODE 851O-01-C:
181
-------
58630
Federal Rescister / Vol. 44. No. 197 / Wednesday. October 10. 1979 I Proposed Rules
Tlbl. 3-1.-Perlormlnce Ind EquIpment
5ptJc1oc1/IOfIS
p..mec.
Speohcat.on
1 ConcoIIorformance Speclficallon 2. to
pvaluo ,the calibration error. response
tlrPP. al j the 2-hour and 24-hour zero
and ~allbration drifts. See example data
sheets (Figures 3-t through 3-7).
"LUNG COO( '~'-lil
182
-------
Federal Register I Vol. 44, No. 197 I Wednesday, October 10, 1979 I Proposed Rules
58631
Figure 3-3. Analysis of Calibration Gasesa
Date
(Must be within 2 weeks prior to the opera-
- tiona1 test period)
Reference Method Used
---
-------
-----
-Hi gh-ranged---
ppm
Sample run
Mid-rangeC
ppm
---
------
--~----------------
------
--- -------------
2
--
-----
--------
3
--------
Average
---
-------
Maximum %
__deviatjone
------------
d Not necessary if the protocol in Citation 10.5 of Perfor-
mance Specification 2 is used to prepare the gas cylinders.
c Average must be 11.0 to 14.0 percent; for 02' see Section
5.2.2.
d Average must be 20.0 to 22.5 percent; for 02' see Section
5.2.1.
e Must be < + 10 percent of applicable average or 0.5 percent,
whicheverTs greater.
183
-------
58632
Federal Rep- I Vol. 44. No. 197 I Wednead.ay. October 10.1979 I Proposed Rules
Figure 3-4. Calibration Error Determination
Run Calibration Gas Measurement System Ar1thmet1c
No. Concentrationa Reading Differences
ODl1l ODIn DDIn
A B A-B .
Mid Hioh
1
2
3
4
5
6
7
8
9
10
11
12
-
13
14
15
Arithmetic Mean (Eo. 2-1)b =
Confidence Interval (EQ. 2-2)b -
Calibration Error (Eq. 2-3)b,r. -
-
aCa ibration Data from Section 6.1
r~id-1evel: C=-ppm
High-level: D - ppm
b See Performance Specification 2
c
Use C or D as R. V.
184
-------
Federal Register I Vol. 44. No. 197 I Wednesday. October 10. 1979 I Proposed Rules
58633
Figure 3-5.
Response Time
Date
High-Range =
ppm
Upscale Downscale
Test Run min min
1
2
3
Average A = B = I
System Response Time (slower of A and B)
min.
185
-------
;,~
"~"'.~"~:;'
.
58634
federal Register I Vol. 44. No. 197 I Wednesday, October 10.1979 I Proposed Rules
Data Time I Zero Hi-Range Span Calib.
set Begin End Zero Rd. . dri ft RdQ. drift drift
no Date Init. Fin. Init. Fin.
A B C=B-A D E F=E-D G=F-C
-
Arithmetic Mean (Eq. 2-1)a
Confidence Interval (Eq. 2-2)a
Zero driftb Ca1.ibration driftb
a From Performance Specification 2.
b Use Equation 2-3 of Performance Specification 2 and 1.0 for R. V.
Figure 3-6. Zero and Calibration Drift (2 hour)
186
-------
Federal Register I Vol. 44. No. 197 I Wednesday, October 10. 1979 I Proposed Rules
58635
Data Time Zero Rdg Zero Hi-Range Span Calib. 1
set drift Rda drift drift
no. Date Beg,n lEnd Init. Fin. Init. Fin.
A B C=B-A D E F=E-D G=F-C
.
Arithmetic Mean (Eq. 2-1)a
Confidence Interval (Eq. 2-2)a
Zero drift b Calibration drift b
a From Performance Specification 2.
b
Use Equation 2-3 of Performance Specification 2. with 1.0 for R. V.
Figure 3-7. Zero and Calibration Drift (24-hour)
IIWNG COIlE '5ICHI'~
187
-------
58636
Federal Regi.ter I Vol. 44. No. 197 I Wednesday, October 10. 1979 I Proposed Rules
6.4 System Relative Accuracy. (Note:
The relative accuracy i. not determined
sl'parately for the diluent momtor, but is
determined for the pollutant-diluent
systl'm.) Unless otherwise specified in
an applicable subpart of the regulations.
the Reference Methods for the diluent
concentration determination shall be
Reference Method 3 for CO. or 0.. For
this test. Fynte analyses may be used
for CO. and 0. determinations. Perform
the measurements using the guidelines
below (an example data sheet is shown
In Figure 2-6 of Perfo~ '~ce
Specification 2J:
6.4 1 Location of Reference Method 3
Sampling Pomts. Locate the diluent'
Reference Method samplmg points
accordmg to the guidelines given in
Section 6.4.2.1 of Performance
Specification 2.
Ii 4 2 Number of Reference Method
Tests Perform one Reference Method 3
test according to the gUideline in
Performance SpecificatIOn 2.
6.4.3 Sampling Strategy for
Reference Method Tests. Use the basic
Rpfcrcnce Method sampling strategy
outlmed in Section 6.4.4 (and related
sub-sections) of Performance
Specification 2.
644 Correlation of Reference
Method and Contmuous Monitor Data.
Use the gUidelines given m Section 6.4.5
of Performance SpeCification 2.
7. Equations. Reportmg. Retest, and
Bibliography. The procedure and
cit,! t ,ons are the same as m Sections 7
Ihro\1l!h 10 of Performance Specification
2.
jr~ n... ~JlroJ FdPd 1o-l}.-~9 845..ml
9M...UHG COO€ &56C)..4 1-"
188
-------
60780
Fed.al Register I Vol. 44. No. 205 I Monday. October 22. 1979 I Proposed Rules
Standards of Performance for New
Stationary Sources: Petroleum
Reflnerlel Review of Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
Particulate Matter
The available data Indicate that the
current limitation on particulate matter
emissions accurately renects the
performance capability of best available
control systems. It is. therefore.
concluded that no revision should be
made to the particulate standard. New
technologies such as high efficiency
separators. high temperature
regenerators. and new catalysts have
'teduced the total quantity of
uncontro~led particulate matter emitted.
However. the method established in the
standard for calculating the allowable
emissions effectively COlTects for the
reduction due to changes in catalysts
and operatil18 procedures.
While it is concluded that the
particulate malter standard should not
be revised. a question has been raised
as to the validity of Reference Method 5
when high concentrations of
condensible .ulfur compounds are
present. This test method. which is used
to measure compliance with the
particulate .tandard. operates at a
nominal temperature of 120'C and. as
such. is capable of collecting
condensible matter \\!hich exists in
gaseous form at stack temperature. If
significant quantities of such
condensible material exist which are not
controllable by the best systems of
emission reduction. then a facility
employing such systems could be found
to be In non-compliance with the
standard. An analysis of data available
when the standard was established
indicated this was not a problem at that
time. However. with high sulfur content
feed. there Is evidence that condensible
sulfur oxides may exist at
concentrations sufficient to affect
compliance.
EPA is cUlTently studying this
question. Depending on the results of
this study. EPA may revise the slsndard
or the t~t method.
Carbon Monoxide
The present standard for carbon
monoxide emissions was established at
a level which would permit regenerator
in Situ combustion. This method of
controlling carbon monoxide emissions
offers production and energy efficiencie8
but is recognized to be less effective
than a carbon monoxide boiler. No new
data were obtained during this review to
alter the original finding that it is not
practical to control CO emissions to leu
than 500 ppm by in situ regeneration
and. therefore. no revision in the
.tandard i. planned at thi. time.
However. it .hould be noted that the
recent advent and increased uae of CO
oxidation catalysts and additives may
provide data showing that
concentrations lower than 500 ppm are
achievable. If such data become
available. the Agency will consider
revision of the standard. It should be
further noted that for the purpose of
attaining and maintaining the national
ambient air quality atandards. State
Implementation Plan new source
reviews may. in some cases. require
greater CO emission reductions than
those required by the standards of
performance for new sources.
At the time the .tandard was
established. EPA concluded that CO
emissions should be continuously
monitored. A requirement for such
monitoring was. therefore. Included in
the standard. This requirement is
applicable to all catalyst regenerators
subject to the standard. However. the
effective date of the monitoring
requirement was deferred until EPA
develops performance specifica tions for
CO monitoring systems. EPA has found
no basis for revising this monitoring
requirement and performance
specifications are cWTently under
development and evaluation. It is
planned to issue an advanced notice of
proposed rulemaklng in 1979 setting
forth the specifications which have been
189
developed and which will be asse~~ed
In field studi~.
Sulfur DioxidB
The present standard currently limits
SO. emissiora resulting from the
combustion of fuel gill. The cataly.t
regenerator i. also a significant source
of SO. emiuion. but ~ not lubject to
the standard. The review considered
both the Deed to revise the current
limitatioD and the need 10 include
limitations on SO. emissions from the
catalyst regenerator-
Available compliance teat dais
indicate that the cUlTent standard
limiting sulfur to 230 mg H.S/dscm from
combustion of fuel gas is being met and.
in some cases. exceeded by a wide
margin. Six tests showed an average of
107 mg H.5/dscm and a range of 7 to 229
mg H.S/dscm. While these data indicate
that a reduction in the present limitation
IS pos8lble. the range exhibited is
consistent with the control device
performance documented at the time the
standard was established. On the basis
of this. along with the increlllled sulfur
content of feedstock expected with
increa8ed imporIAI and the variable
crude oil supply conditionl now
existing. it i. concluded that the fuel gas
sulfur limitation II appropriate and that
no revilion is needed.
A deficiency in the current Itandard
limiting .ulfur in fuel g81 relatel to the
lack of a continuou. monitoring method.
EPA recognized the need for continuoWJ
monitoring at the time the standard was
adopted. However, at that time. 00
monitoring system. had been
demonstrated to be adequate for this
purpole and EPA had not estaula.hed
performance specifications for such
systems. Consequently. appucalton of
the monitoring requirement WII8
deferred until performance
specifications could be adopted. Since
the adoption of the standard. EPA hili
pursued a program to develop and
asseS8 the performance of an H.s
monitoring system. On this basis.
performance specifications are now
being developed. It is planned to LSsue
an advanced notice of propoled
rulemaking in 1979 setting forth the
specifications which have been
developed and which will be aaaeued
in field studies.
-------
Federal Register I Vol. 44. No. 205 I Monday October 22. 1979 I Propoled Rules
realized b, IIIIq prebeaten. -pedaOJ
IUlpeDlloR prebelten. Ii botla
The.. proce.. cbaDsel 1ft .
pOlltlve and ne,llive effec:tl OD
particulate eml..lou. The repllcameat
of wet procell UDiIl with dry procell
,mitl Increa.e. potential emI..lon..
particularly In the artndlns. m.txtna.
blending. .torege. and feeding or raw
mater1al. to the kiln. The ,ulpen.loa
preheater. on the other bend. tend. to
deere..e particulate emilaloDl due to 118
muJticyclone conetructlon. It aiao
ensure. more thorouab contact of the
kiln exhau.t lIa.e. with the feed.
material whlcb may Inere..e .orption of
aulfur oxide from the exhauat on the
feed. 0
Economic Considerations. Almost a
cement produced 18 utilized by the
construction Indu.try. A. e re.ult. the
production of cement foUow. the
cyclical pettem of the construction
industry. Relatively hiJh ce~ent .
production ha. ocCUlTed dunng penode
of growth in new home and other.
con.truction market.. and production
hal decreased In .uch period. of
recession.. occurred in 19'7~1975.
In contralt, over the .hort term.
production cap8dty ba. not cIoaely
paralleled actual production. Thi. il due
apparently to the lead. time re~uired to
add capacity. to the dlfficuJty 111
accurately predictin8 future demend.
and to economic and other facton
including tha effect of pollution conlrol
requirement. on the clo.ure of old.
marginel plante. .
An examination of production and
capacity over the past 10 yean suggeate
the difficulty which the Industry ha.
ellperienced In attempting to meet.
demand while avoldins excell capacity.
In the early 1170'.. utilization of
production capadty wa. greate~ than 110
percent. However. wage and pnce
control. were In effect from 1971 to 1973
during which time the indu.try
experienced 118 lowest profit margin
since the 1930'.. New plent construction
wa. po.tponed wbile IOme older ~Iant.
were bein8 clo.ed. AI a result, regional
cementsbortsge. occurTed in 1972-1971
When price control. were removed in
1913, the price of cement jumped 14
percent and .ome new capacity
construction wu begun. Sbortly
thereafter. the Country entered a
recession end cement production feU to
70 percent of capacity. .
The cyclic OCCUITence of high .demand
exceeding capacity haa been eVidenced
again in the pa.t aeveral yea~a. The
rapid growth in the con.lruction
Industry .ince 1975 has increased the
dpmand for cement and parts of the U.s.
have .een .bortage.. particularly in the
West. At the same time, the industry hu
40 C~ P8rt 60
"taI>datds 01 Performance lor New
tt.etlonary Sources; Portland Cement
ltanll; Review 01 Standarda
AOIJ8CY: Environmental Protection
Agency (EPA).
AC'TIOw. Review of Standard..
SUMMARY: EPA has reviewed the
standards of performance for portland
cemenl plants (40 CFR 110.1101. The
review is required under the Clean Air
Act. as amended Augu.II977. The
purpose of thi. notice I. to announce
thaI. ba8ed on an 898eS8ment of the
industry. applicable control technology.
and result8 of performance test.
conducted pursuant to the 8tandard.
I'!'A has determined that no revision 10
,/10 particulate eminlon IImllatlon \8
needed but that the 8tandard should be
revised to rPQuire contlnunno nn>lCllV
monl1or1r1j!.
DAns: l..omments must be received by
December 21. 1979.
SUPPLEMENT ARY INFORMATION:
Background
On August 17, 1971, the Environmental
Protection Agency proposed a standard
under Section 111 of the Clean Air Act
to control particulate mailer emissions
from portland cement plants. The
standard. promulgated on December 23.
1971, applies to any facility constructed
or modified after August 17. 1971. which
manufactures portland cement by either
thp wet or dry process. Specific affected
faCilities are the: kiln, clinker cooler.
rllw mill 8ystem. finish mill system. raw
mill dryer, raw material storage. clinker
storage, finisho?d product slorage.
conveyor transfer points. bagging. and
bulk loading and unloading and
unloading systems.
The standard prohibits the discharge
intll the atmosphere from any kiln any
gases which: .
1. Contain particulate mailer In excess
ofO.1S kg/Mg (0.30 Ib/ton) feed to the
kiln. ur
2. Exhibit greater than 20 percent
opa, ,ty.
Tf. , standard prohlbit8 the discharge
1I1to e atmosphere from any clinker
cool. any gases which:
1 L ntain particulate mailer in exce98
of 0 0:, I kg/Mg (0.10 h/ton) feed (dry
b,,,,, Ito the kiln. or
~ f:\hlbiI10 percent opacity or
grPiI ter.
The 8tandard prohibits the di8charge
into the atm08phere from any affected
facility other than the kiln and clinker
cooler any g88es which exhibit 10
percent opacity. or greater.
The Clean Air Act Amendment. of
1977 require that the Administrator 0'
the EPA review and. if appropriate.
revise e81ablished 8tandards of
performance for new stationary source.
atlea81 every 4 yean [Section
111(b)(I)(B)). Thi8 notice aMounce8 that
EPA has undertaken a review of the
8tandard of performance for portland
cement plant8. As a result of this review.
EPA has concluded that the present
particulate emission limit i8 appropriate.
and does not need revision. However. a
provision to require opecity monitoring
8hould be added. In addition. EPA ia,
however. planning to undertake a
program. in its Office of Research and
Development, to investigate and
demonstrate methods such as
combustion modifications which could
reduce NO. emissions from combustion
used in process sources such as cement
plants. Positive results from this
program would form the basi8 for a
possible revision to the standard in 1982
or 1983. Comments on these findings and
plans are invited.
Finding.
Industry Slatus
Capacity. There are cUlTenlly 53
cement companies producing portland
cement in the U.S. The 53 companies
operate 158 cemenl plants throughout
the U.S. with single plant capacity
ranging from 50,000 Mg to 2.161.000 Mg
per year. The industry also includes 8
plants with only clinker grinding
facilities which use either an imported
or domestic clinker as feed material.
Cement plants are found in nearly every
State because of the high cost of
transportation. The actual clinker
capacity of these plants is also
distributed throughout the U.S.. although
some regions have linle capacity due to
a lack of demand; and although many
areas of the Country are presently
expenencing cement shortages and
delays. announced capacity increase. in
these areas are still small.
Energy Consideration8. The portland
cement industry is very energy intensive
with energy costs accounting for
approximately 40 p~~L"nt of Ihe cost of
cemenl. Accordingly. significant
emphasis in the industry is on increasing
energy efficiency. For this reason,
almost all new and planned construction
will use the dry process which can be
twice 8S enprgy efficient as the wet
process. Additional savings can be
190
60781
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6078Z
Federal Register I Vo\. 44. No. 205 I Monday, October 22. 1979 I Proposed Rules
not rapidly added DeW capacity,
although th. Bureau of Mine. projecta
high demaacllD dn! early 1980"..
In CQIIItdariDg whether pollution
control coatllnfluencad the recent 181 ID
cepaclty. the Counct1 on Wage and Prica
Stability coDCluded that
. . . tb8 addad poIIutlo8 DllDtroI 110818 cia
challla the wa, a fIn8 would coaaider 8 new
Inve.lmaal dec:iaIoa b, maJdns larser prb
tncra.... Dece8l8lJ for the expendilUrellD
be commltled. l1li. dOlI DOt mean that the
Impo.illon of theM oootrota be. neceuarn,
cau.. anJ reductlooln - cepedty
expenditure. In the cement Indua!rJ.
However. thie aaal,.18 doea leave opeII the
pOlllbility thaI aD jav..tment decaaioD could
be chansed for a marginal plant because of
pollution control coete (particularly a planl
.ellins cement for S40 per ton and u.m, a 12
percenl rata of return). (Price. and Capacity
Expansion in the Cement Indrutry, Council
on Wase aad Price Stability, W..hinatoo.
D.C.. 11177.1
Since cemenlla already selling for ..
high a. $53 per ton on the We.t Coast, It
I. very likely that capital investment
will not be stifled by pollution control
expenditurea.
Emission Control SkJtU6
Fifty-one cement kilna and clinker
coolers have been identified which are
opera ling and are subject to the new
source performance standard. Of thelle,
49 are in compliance with 0.15 kg/Mg
kiln feed (kiln) and 0.05 kg/Mg kiln feed,
(cooler) emillion lImil8. One completed
kiln has only recently been tested and
data are not available; and one facility
hIlS notified its State authority that it
cannot meet the standard.. Also. five
cement kilna potentially subject to the
standard were identified for which data
were not available: Tbe number of
sources with other NSPS-affected
facililies Was not determined. although
there are none reported that are not in
compliance with the applicable 10
percent opacity standard.
For the 29 kilns and 20 clinker cooler.
which were in compliance. the kiln test
results averaged 0.073 kg/Mg and
ranged from a high of 0.142kg/Mg feed
to a low of 0.013kg/Mg feed. The range
for kilns with emissioOl contJ'olled by
ESP is 0.142 to 0.020 kg/Mg. and for kiln8
". a~. r.\bric mler ~ajhousea the range is
0.1J2 to 0.013 kg/ Mg dry kiln feed. The
data indicate that neither the ESP nor
the baghou8e i. significantly better at
contJ'olling cement kiln particulate
ma Iter emiuion..
Cement plant clinker coolers have
been tested at emission levels ranging
from 8 high oT 0.061 kg/Mg to 8 low of
0.005 kg/Mg d."}' kiln feed with a mean
of 0.024 kg/Mg. ComplillllC8 test data on
a single wet scrubber show emiuions
near the mean emission level for fabric
mter bagboUie control. (0.022 kgfMs).
Oat8 for affected faclUtie. using gravel
bed mten indicate a mean eCliuion
level of 0.034 kg/Mg dry feed (O.o2J-
O.045kg/Mgj.
Tbe compliance te.t data were
analyzed to determine if the type of
control technology. the process I)'pe (Le..
wet or dry~ or Interaction of process
type and control technology affected the
ability to control the emission of
perticulate matter from portland cement
kiJn.s or clinker coolers. This an.al}'si.
Indicates that no control technology ill
use today i. more effective for
contJ'olling particulate malter emission..
Although comparison of mean values
Indicates that the possibility that
emissions from dry procell kilns are
controlled slightly more effecli\'el}' than
wet process kilns. the dlffereoce 18 oot
statistically significanL
Nitrogen Oxide Emiuionll
Cement kilns are a very large and
presently unregulated source of nitrogen
oxides [NO.) emissions. Based upon
estimated NO. emissions of 1.3 kg/Mg of
cement produced and 71.4 million Mg of
portland cement produced in 1977. d.O
estimated 93.000 Mg of NO. were
emitted by portland cement plants that
year. The main factors that result in the
production of NO. are the flame and kiln
temperature. the residence time that
combustion gases remain at this
temperature. the rate of cooling of these
gases. apd the quantity of eKcess air in
the flame. Control of these factors may
permit the operator 10 shaf1:ly ~edllce
the emission of NO.. but such pr.,r.tices
have not been demonstraled in c~ment
plants for NO. emissio!\B.
Opacity Monitoring
When the NSPS for porlland cement
plants was established in 1:0':'1 no
provisions were included 10 ro'" .Jre
continuous monitoring of OjJdClty. 111is
was. in part. because the piesence of
water vapor in the exhaust ga~es from
wet-process facilities would df;ect
monitor accuracy. In addilJon.
monitoring syslema had not teen
demonstrated at baghoulle conl~ujled
191
facIlities where stack gases dre emllted
from roof monitors or multiple stub
stacks. However, since tbe standard
was adopted, a monitoring Sj ,tern hils
been demonslrated at a steel plant
utilizing baghouse controls and stub
stacks.
Conclusions
On the basis of the CJndlI~gS which are
summanzed above. EPA has concluded
tha t the cUlTent particula te IJU! Iter
standards are appropriate and effective
and that no revision is needed. Wlule
the compliance tpst data do show that
the mean results are well below the
standards, the range oC data Sl: ~l'~t that
the stand.Jrd IS set at a level \\ hirh
renee!s thp perfurmance oC the best
systems of emission reduction.
However. it is concluded that the
standard should be revised to Include
provisions requiring the continuous
monitonng of opacity. This conclusion is
based upon the de~on~tratlon of
opacity monitors on bag house stub
stacks and on the shift in the pnr11and
cement IndlJslry toward the dry process.
as well dS EPA's belief that ccn!lnuous
mon:!om:,Q repres!'nts an importdnt and
erCecti\ e medns for assuring proper
op.!ration and maintenance of
particulate miltter control equipment.
Adoption oC any opacity monitoring
requirement wdl be preceded by a
proposill and the opportunity Cur public
comment. The Agency expects to
unJerldke de\'eJopment ilnd to propose
this revision during 1980.
It is also concluded that the !dck oC
demonstrated control technolugy and an
emission limitation Cor NO, is an
important deficiency. The A!!eRcy is
thereCore planning to evaluate. develop.
and demonstrate mpans Cor limiting NO,
emissions. This program, which will
includp other industriill procps~ fuel
users, will be aimed al tran~fl'mng
technolo~y bein!! employpd to control
NO, emissions from sleam gener;lfnrs. If
this proves successful. the results wdl be
used as a basis Cor development of :'liD,
~tanddrds.
Public Participation
All interested per~ons are iO\ !'I'd to
comment on this review. the
conclusIOns. and EPA's planned aLlion.
Dated Orl"bpr 16. 1979.
Dougla, M Costle.
t,l:nll;J~/r(J'or.
-------
fed,p"al Register / Va\. 44, No. 234 I Tuesda}', December 4. 1979 / Proposed Rules
89683
ENVIRONM£NTA1. PROTECTION
AGENCY
40 CFR Part 52
(FRlI352-4)
Approyal and Promulgation af
Implementation Plana; Florida: .
Varianu tor Particulates, 502. Visible
Emissions and Excess Emissions tor
Florida Power and Ught Generating
Planls
AGENCY: Environmental Protectll r:
Agen,y
ACTIO~: Propo~ed rule
SUMMARY: On August 31. 19~9, the S'alt'
01 Florida aubmilled to EPA. as a Sll'
reVISion. a variance which had been
adopted by the Environmental
Re~uldllon CommIssion This vananr..
.Uo.... s the Florida Power & Light
Company (FP&L) to contmue certam
operdl1ons during the current low-sulfur
oil shortage. The variaDce rel,Ptes the
req"""ments which certam FPIltL
gpner>ltmg unita muat meet with regard
to elT' Issiuna of particulates and su:.J ur
d,u~jde, viaible emi..ions and excess
I'TIJISSlonl. EPA propoles to approve the
rpl ISlon except for certain porllons
which the Agency proposes to
dls~pprove. The public IS mVlted 10
cOlT'ment on the proposed actions
DATES: To be considered. commenta
musl [,e received on or before January 3,
19RO
ADDRESSES: Written comments should
be HJdressed to Archie Lee of EPA
Region IV's Air Programs Branch (See
EPA Region IV address below). Copies
vI the materials submitted by Florida
ma} be eXdmined during normal
business hours at the following
locations:
I'ul,l,( Inf"r'l1ation Reference Unit, Library
~\' 'pms IJ-anch Environmental Prolecl",n
A~, nr;- 401 M Street. S W., Washington,
D l 2"41-iO
Llbr"l, En\'''''nmelltul Protection A!!en,y,
Reg;on IV. 345 Courtland Street. N E.
AI!,lnla. Georgia 30308
FI"r ..d Bur.au 01 A" Quality Management.
D. dflmenl of EnvIronmental Regl;lahon,
1 1 Tuwers Office Building. 2600 Bla"
SI ' Road. Tallahassee. Flonda 32301
FOR F 'RTHER INFORMATION CONTACT:
Aro,:I1~ Lee 01 EPA Region IV's Air
Pr.",-..",s Branch. 345 Courtland Street,
N.E., Atlanta, Georgia 30308. Telephone
404/881-3286 (ITS 257-3286).
BACKGROUND: In early 1979 Florida
Power and Light Company was unable
to obtain a sufficient supply of low-
eulfur fuel oil due in part to the
decreased availability of crude and the
disappearance of "apot market" low-
aulfur oil supplies. Consequently. FP'~
petitioned and received emergency. relief
under section no(£) or the Clean Air
Act. The relief granted under section
nO(£) is limited in time and therefore the
need for a longer period of relief has
arisen. On Auguat 28, 1979. the Florida
Department of Environmental
Regulation issued a variance which
relaxes the current particulate limits of
o.llbl. per MM BTU and 2091, opacity.
Under the variance Cape Canaveral 1 &
2, Fort Myers 1 a 2, Manatee 1 & 2 and
Sanford 3. 4, and 5 may emit 0.3 lbs. per
MM BTU. and Port Everglades 1. 2. 3.
and 4. Riviera 3 & 4, and Turkey Point 1
& 2 may emit 0.4 Ibl. per MM BTU.
Opacity limits for all units are relaxed to
40"0. Additionally, the variance
stipulates that if fuel oil with asphaltene
content of less than or equal to 991, by
weight is burned. the following limits
will applv to al1 units: (1) 0.3 lbs. per
MM BrU, or (2J 0.2 lbs. per MM BTU (for
units with low excel8 air bumera).
Excess emi..ions are aUowad during
perioda of malfunction Ind startup/
ahutdown operltions. During boiler
cleaning and load changes. emission
limits of 0.8 lbs. particulate per MM BTU
and 60% opacity apply. (These periods
are not to exceed 3 houra in any 24-hour
period.) Opacity grelter than 80% is
allowed for not more than four &-minute
perioda durina the 3-hr. period.
providing the unit has Inatalled and
operating. or has c:munitted to ins taU
and operate. continuous opacity
monitors.
The aulfur dioxide limitations for
Manatee Units 1 & 2 are relaxed from 1.1
lb. per MM BTU to 2.75 lbs..per MM
BTU.
Control strategy demonatrations
purporting to show compliance with the
National Ambient Air Quality Standards
and PSD increments for total suspended
particulates ar,d sulfur dioxide are
included with the State submittal.
EPA has reviewed the materials
192
submitted by the State of Florida and
finde the revleion to be approvable
except for the following areas:
1. No testing method for compliance is
epecified. The State. in a recent
eupplement to the variance. haa ordered
FPc\L to test for particulates using EPA
test method 5 or 17. This Infonnation.
along with the teetlng method for aulfur
dioxide, ehould be aubmitted to EPA 81
part of the SIP revision package.
2. Relaxing the TSP limite for the
Turkey Point and Port Evergladea plante
would allow FP&L to bum higher sulfur
fuel. thereby violating the s\llfur dioxide
ClalS I increments in the Everglades
National Park. The alternate Class I PSD
incrementa for sulfur dioxide were used
(in the control atrategy) to accommodate
emissions from the Turkey Point and
Port Everglades plants.
EPA has detennined that lince thil
SIP revision does not involve the
pennitting of a major new source or
major modification. the alternative
Class I increments cannot be used.
Therefore the air quality impact of the
SIP revision must not violate the
atandard Clan I Increments. Since the
limits on allowable sulfur dioxide
emissione for the Turkey Point and Port
Everglades plante would not be violated
even by the higher sulfur oil projected in
the variance. It is evident that the
cunent SO. emission limits applicable 10
these planta are not adequate to protect
the CIa.. I increments. The State ahould
initiate action to revise the SO. emillion
limits for these two plants.
EPA is today proposing to approve the
Florida revision except for the portions
affected by the deficiencies just
deacribed; it is propoaed to diupprove
the latter portiona.
The public Is invited to participate in
this rule making action by submitting
written commente. After reviewing
pertinent comments and all other
Infonnation available to him. the
Administrator will take final action on
the Florida revision.
(Section 110 of the Clean Air Act (42 U S.C
7410))
-------
76786
Federal Regiliter I Vol. 44. No. 250 I Frida}'. December 28. 1979 / Rules and Regulations
._-------~-- ------ ----
ENVIRO~MENTAL PROTECTION
AGENCY
40 CFR Part 60
IFRL 1366-31
Standards of Performance for New
Stationary Sources; Adjustment of the
Opacity Standard for a Fossil Fuel-
Fired Steam Generator
AGENCY: Environmental Protection
Agency [EPA).
ACTION: Final rule.
SUMMARY: This action adjusts the 1\5PS
op;lcity standard (40 CFR Part 60.
Subpart D) applicable to Southwes!em
Public Service Company's Harrington
Station Unit #1 in Amarillo. Texas. The
a, tion i~ based upon So~thwestern'8
ceffionstration of the cunditions that
entille it to such an adjustlTIt:1t u~der 10
C!R [;0 11(e).
EFFECTIVE DATE: December 28. 1979.
ADDRESS: DLlcket :>10. F:'J-79-13.
containing materia! ~ele\ ar.! 10 this
nil.".:.,; '8. is I"tuted in the U.S.
Er., 'r,,,. -::.;,ntal PrlJ:ecli.;n Ase,1cy.
C, nl"l Docket Section. Rou.n :9113 8.
4tH M St.. SW.. Washington. D.C. 20460.
The docket may be inspected between 8
a.m. and 4 p.m. on weekJays. ,)OJ a
redsonable fee may be dw;ged far
cc,pyir1g.
The docket is dn or:;anized 8'1d
((;mplete file of alllhe information
sub:nitted to or oth~rwise considered Ly
tpe Adrrdnistrahlr in the Je~el()pmer:t of
th:s mlt'ma1.ing. The dlJckeLng s~ slem is
inteded to "How members of the public
dnd inc1dstries involved to readily
identily and locale documents so that
thrv can inte1l!gently and effecti\'ely
p:!;'lIcipate in the rulemaking process.
FOR rURTHER INFORMATION CONTACT:
Rich,.rJ B!or,di. Division of Sldtio'1'.uy
S,'"r::e Enforcement (EN-3-1!).
Em'iro:lmental Protection Agency. 401 M
Slrl'ei. SW.. Washington. DC 20460.
telephone :'110. 202-755-256-1.
SUPPt.EMENTARY INFORMATION:
Background
The standards of performance for
fossil fuel-fired steam generators as
pl'Omulgated under Subpart D of Part 60
on December 23. 1971 (36 FR 24876) and
amended on December 5.1977 (42 FR
131537) allow emissIOns of up to 20%
opacity (6-minute average), except thdt
27".: opacity is allowed for one &-minute
period in any hour. This slanddrd also
requires continuous opacity mO:lltorln~
and ;eqlllres rpportir.~ as "Xu'ss
P.1'1 i ssions all huurly periods durmg
\\'r.:ch there are two or more 6-mlnute
periods when the a\'erage opacity
exceeds 20'C~.
On December 15.1977. South\\estern
Public Sen'ice Compdny [SPSC) of
Amarillo. Texas. petitioned the
Administrator under 40 eFR 60.11(e) to
adjust the 20% opacity stand.trd
nppllcable to its Harrlr:gton Station
coal-fired Unit :<11!1 Amarillo. Te\as.
1 /;p '-\dmin,clralcr proposed. on June 29.
1Y79 [44 FR 379601. to g.-ant th~ pt'tJtion
for adjustment, cor.cli.dlng that spse
h :u demonstrated tl,e prbPnce at ils
fIarr:ngton Station UnIt =1 of Ihe
cunditions that entitl~ It to ouch rela'£.
as specified in 40 CFR 60.11[e)[3).
These final reguldtions are ide'1tical to
tf.,e proposed ones EPA hen'by grants
SI'SC's pet:tio[1 for adjustment for
: IdI""Zt,,[1 51,111On UnIt '=1 from
cu;'1;;1;.i:"ce with the ";:;uL,ty sl,Jnd,lrd of
40 (;FR 6O.42[d)[2). /\~ .. ;1 al!('m.lIi\'e.
SI'SC :.!-J"II ::01 cal:se te> be d,,,:hdrp,rd
;: :u the atmosphere ~iU:n tlie Ildlrington
S:..t'un Unlt:<1 dny ga,es "hlLh exhibit
gll'.J.er t}-H~n 35,J,., llpdCI:Y (J minute
il\ l,r..~el. except that u ".a"irnllm of ~L '"
UO.:t.1tv .;h~Jlllle nerrndft'd fdr fLul more
tt~ 'n ":'e tJ<"lln\Jl~ f)' ,1:1J In dllV htlur.
Tit " ;](ijus'mel'l wiii r.c;t rc!ip\';' spse of
tis ~)~jIB.t::on 10 cumpi) wIth ,IIlV .\I~!!r
(1'\I~.~,d, ~I;ttc or IOr:HI (l~\acity .
n'ljll;rpmP',!I~. or ~,H! ul!rlte O1rt1t..r S02
or "~Oli cont!"cd rr~'J'~(~:71pnl~
Comments
1',\0 Ll'OImcnt Irl!ers w~re rl'Cl'I\"d.
bt,th from industry .,r.d h'Jth suppu.-tmg
the proposed achen One IrHh:stry
revescnlali\'e appro\ "d 0: FI ':\ effOl t~
to ddj::st '\SPS 10 acc"",,1 f()r \\',.11-
k,,"\\n apd..-ily d,f£;Cl.lI./'S i"ul.d "I,,-ge
:.;tei:tm ei(lc~:-'c gCI.L'ra~ln6 u.litS '... r. ....h
ha\'e hCJt side ,':('ctTl"I~lic pre~,pdd!Llrs
"nd CQ;r,LJu,t !()\\-sulfur \\['ol(',n Lt.dl.
:\ seconulr:d1Jstry fI';Jrcscn! dIve
,"gg~sl['d th..t Ihe U'L .,j [Jlot ..\L ,I.'db!e
('ontrol Tt" hp.:Ji')gy on ~ [,rt:-flreu ltn!ls
h..s -.01 assu;,~d comr-I'dnce with
ap!,I'''.ible "Pdc:ly :.Irind. rds. dl1d II'dt
cp;]city s'oIndurds do 110t c()mpl('ml'nt
193
:'!.Jnd,tlus fur p.Htlf IILtle .'ml','"II(J~1'" LP:\
d,<..itgrees with this Lumment. V1oLtllon3
of opacity stanJdrds ger:erally r,.Oo:cl
VIOi.ltions of mass emiSSion otartd;]r.!,.
dl'J EPA \\'111 continue 10 'mpo,e ,.p.H:lty
st.lnddrds oIS 01 vdlul'd lu,,11I1 i''':I'.tI~
pl\Jper 0pt'L'llon dr~J rn.untt't1dl1l t' l,t .111'
pc-lIutlon control del ICl'S.
Miscellaneous
This revision is prom\llga IPd undn the
authority cf Section 111 d~d 301(a) or
the Clean Air Act. as amended [42
U.s.C. 7411 and 7601[a)).
Dated: December 17.1979.
Douglas M. Castle.
Administrator,
PART 60-STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
40 CFR part 60 is amended as follows:
Subpart D-Standards of Performance
for Fossil Fuel-Fired Steam Generators
1. Section 60 42 is afTIended by dddlOg
pcragraph [bJ(1) as follows:
~ 60.42 Standard for particulate mal1er.
(.I)' . .
Ib)[l) On and after (the dd!e of
publjcation of this amf'ndmpnt). no
uwner or operator shall cause to be
discharged Into the almosphere from the
Southwc;!ern Puhlic Service CUiTlPdny's
Harring!urt Station L'n;t r1. in .'\mdlillo.
TpXdS. any gesps ",f.,'ch exh:l!il grr'e!nr
than 350111
2. Sf'Ltio!16G,15:~;(1) I> ..~1, ,:.!..(i hy
ddJing pdr~graph (i) as fallows
~ 60.45 EmIssion and ruel monitonng,
(g)' . .
(1)' . .
1'1 For sources subjeLt 10 Ihr ,,[',j( ,tv
st.mdard of ~ 60.42(1J;11). e,u:.s
e~lissions are deflOed as ar.\' SIX rtllrtu!e
pPII()d dullng WhlLh Ih, d\C-r.'~I' cJ,.wity
nr f,~isSH'I-:S exceed'! 35 pfiLt-rtt "Pd( Ity.
(,~ (.('pt th,d one 5lx-mlllLlte it'.'f'f ,I~" pl~r
hour d up !u ~2 p,'r; .:nl OpJ/ulv fit ,d
rt,,1 IJe lI'purted.
I k ~)')'- ~ ~(I'"''t.j Fd,-d 12 2~ -4 '\ ~. ''''''1
BILLING CC[)£ 6~1-M
-------
7762
Federal Regisler I Vol. 45. No. 24 I Monday. February 4. 1980 I Proposed Rules
ENVIRONMENTAL PROT£CTION
AGENCY
40 CFR Part SO
(FRL '353-31
Standards 0' Performance 'Of Ne.
Stationary Sourcea; Ammonium
Sulfate Manuf.cture
AGENCY: Environmental Protecllon
Agency (EPA).
ACTIOM: Proposed Rule and Notice of
Public Heanng.
SelectIOn of MOnitoring ReQulrement~
To further ensure Ilat installed
emiSSion control systems conl1nuouslv
comply With standards of performance
through proper operation and
maintenance. monitoring requirements
are generaUy included in standards of
perfonnance. In the case of ammonium
sulf"te dryers. the most straightforward
means of ensuring proper opera lion and
maintenance is to require monitonng of
actual particulate emissions released to
the atmosphere Currently. however.
there are no continuous particulate
monitors in operation for ammOnium
sulfate dryers. and resolution of the
8amf'llng problems and development of
perfocmance speclficallons for
continuous parllculate monitors would
enlall a major developmenl program For
these reasons. conhnuous morutoring of
par!lculale emissions £rom ammonium
sulf d Ie dryers Knot reqwred by the
proposed standards.
The best indirect method of
monitoring proper operation and
maintenance of emission control
equipment is to continuously monitor
the opacity of the exhaust gas. The
proposed opacity limll for ammonium
sulfate dryers is 15 percent. However. in
the case of ammonium sulfate dryers.
the character of tbe exhaust gas when
wet scrubbers are used for emission
reduction precludes the use of
continuous in-stack opacity IllOniiors.
Where condensed moisture is present in
the exhaust gas stream. in-stack
continuous morutoring of opacity is not
feasible; water droplets and steam can
interfere with operation of the
monitoring instrument. Since most
affected facilities are likely to use wet
scrubbers. continuous monitoring of
opacity is not required by the proposed
standards.
An alterna tive to particulate or
opacity monitors is the use of a pressure
drop monitor as a means of ensuring
proper operation and maintenance of
emission control equipment. For venturi
scrubbers. particulate removal
efficiency is related directly to pressure
drop across the venturi; the higher the
pressure drop. the hilZher the removal
efficiency. For fabric filters. pressure
drop is used a5 an indicator of ex.cessive
flll..r reslslance or damaged filter media.
Therefore. in order to provide a
conllnuous indicator of emission control
equipment operation and maintenance.
Ihe pruposed standards would require
Ihat Ihe owner or operator of any
194
ammcnium sulfate manufacturing planl
subject to the standards instal/.
calibrate. maintain. and operate a
monitoring de\'il:e which continuously
measures and pe~manently records the
total pressure drop Dcr09S the process
emission control syetem. The monitoring
device shlll have an accuracy of ~5
percent o,.er its operating range.
The proposed standards would also
require the owner or operator of any
ammonium sulfate manufacturing plant
subject to the standams to instan.
cal:bra!e. mamtain. and operate now
monitoring devices necessary to
d~termme the ma~s now of ammonium
sulfa!e feed material to the process. The
flow monitoring device shall have an'
accuracy of ~ 5 percent over its
opera ling range. The ammonium sulfate
feed streams are: for synthetic and coke
oven by-pr:>duct dmmonium sulfate
pl,mls. Ihe sulfuric acid reed stream 10
the reactor/.::rystallizer; ror caprolactam
by. product ammonium sulrate plants.
the o"lmation ammonium sulfate stream
to the ammonilll1l ..In.te pia and the
01 e\llll stream to the C8 pralacSalll
rearrangement reaction.
Record. of pressure drop and
calibration measurements would have to
be retained for at le88t 2 years followm,
the d.te of the measurements by owners
and operators subject to this subpart.
This requirement is included under
, 6O.7(d) of the general provisions ol40
CFR Part 80.
-------
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Wednesday
February 6, 1980
Part IV
Environmental
Protection Agency
Standards of Performance for New
Stationary Sources for Electric Utility
Steam Generating Units; Decision in
Response to Petitions for
Reconsideration
195
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8230
Federal Register I Vol. 45. No. 26 I Wednesday. February 6. 1980 I Rules and Regulations
new standard under Subpart Da, While
this statement is true. these units. which
were designed and operated to meet the
old standard. incurred only five
exceedances of the new standards on 8
monthly basis. Moreover. a review of
the available 34 months of continuous
momtoring data from six utility boilers
revealed that they all operated well
below the applicable standard (OAQPS-
76-1. V-8-1).
In addihon. UARG argued that the
available continuous monitoring data
demonstrated that the Agency should
not have relied on short-term test data.
Citing Colstrip Units 1 and 2. they noted
that less than on~third of the 3G-day
average emissions fell below the units'
perfonnance test levels of 125 nglJ (0.29
Ib/milllOn Btu) heat input and 165 nglJ
(0.38 Iblmillion BIu) heat input.
respechvely, They further maintained
that this had not been considered by the
Agency In fact. the Administrator
recognized lit the time of promulgation
that emission values obtained on short-
term tests could not be achieved
continuously because of potential
adverse side effects and therefore
established emission limits well above
the values measured by such tests (44
FR 42171. left column). In addition. EPA
took into account the emission
variability reflected by the available
continuous monitoring data when it
established a 3G-day rolling average as
the basis of detennining compliance in
the standards (44 Fa 33566. left column).
UARG also maintained in their
petition that EPA should not rely on the
Colstrip continuous monitoring data
because it was obtained with uncertified
monitors The Administrator recognized
that the Colstrip data should not be
relied on in absolute tenns since
mom tors were probably biased high by
appr')'lmately 10 percent (OAQPS 76-1.
111-8-2. page $-7). EPA's analysis of
data revealed. however. that it would be
appropriate to use the data to draw
conclusions about variability in
emissions since the shortcoming of the
Colstrip monitors did not bias such
findings. This data together with data
obta ,.(..j using certified continuous
mon) 'S at five other facilities (OAQPS
76-1. -B-1. page s-3) and the results
from, .day test programs (manual tests
pI' rf 0 IT. ed about twice per day) at three
addlhonal plants (OAQPS 76-1. 11-8-62
and 11-8-70) enabled the Administrator
to conclude that emission variability
under low-NO, operating conditions
was small and therefore the prescribed
emissIOn levels are achievable on a
continuous basis.
UARG 'irgued that since the only
continuous monitoring data available
was obtained from boilers manufactured
by Combustion Engineering and on a
limited number of coal types. the
Agency did not have a sufficient basis
for finding that the standards can be
achieved by other manufacturers or
when other types of coals are burned.
The Administrator concluded after
reviewing all available information that
the other three major boiler
manufacturers can achieve the same
level of emission reduction as
Combustion Engineering with a similar
degree of emission variability (43 FR
42171. left column and 44 Fa 33586.
middle column). This finding was
confirmed by statemen.. submitted to
UARG and EPA by the other vendors
that their designa could achieve the final
standards, although they expre88ed
some concern about tube wastage
potential (OAQPS-78-1, UI-D-811.
attachment-KVB report. pages 118-121
and IV-D-30). EPA has considered tube
wastage (corrosion) throughout the
rule making and has determined that it
will not be a problem at the NO.
emission levels required by the
standards (44 Fa 33602, left column).
With respect to different coal types, the
Agency concluded from its analysis of
available data that NO. emissions are
relatively insensitive to differing coal
characteristics and therefore other coal
types will not pose. compliance
problem (43 Fa 42171. left column and
OAQPS-78-1. IV-8-24). UARG did not
submit any data to refute this rmding.
UARG also argued that the continuous
monitoring data should have been
accompanied by data on boiler
operating condition.. EPA noted that the
data were collected during extended
periods representative of normal
operations and therefore it renected all
operational transients that occurred. In
particular. at Colstrip units 1 and 2 more
than one full year of continuous
monitoring data W88 analyzed for each
unit. In view of this. EPA believes that
the data base accurately renects the
degree of emission variability likely to
be encountered under normal operating
conditions. UARG recognized this in
principle in their January 15 comments
(Part 4. page 15) when they stated that
"continuous monitors would measure all
variations in NO, emissions due to
operational transientl. coal variability,
pollution control equipment degradation.
etc,"
In their petition. UARG restated their
January 1979 comments that EPA's
short-tenn test data were not
representative and therefore should not
serve as a basis for the standard. As
noted earlier. EPA did not rely
exclusively on short-term test data in
196
selling the final regulations. In addition.
contrary to the UARG claim. EPA
believes that the boiler test
configurations uled to achieve low-NO,
operatlonl renectlound engineering
judgement and that the techniques
employed are applicable to modem
boilers. This il not to lay that the boiler
manufacturers may not choose other
approaches IUch allow-NO. bumers to
achieve the Itandard.. While
recognizing that EPA'ltelt program was
concentrated on boilers from one
manufacturer, lufficient data was
obtained on the other major
manufacturerl' boilers to conflnD the
Agency's finding that they would exhibit
similar emission characteristics (44 Fa
33566. left column). Therefore. in the
absence of new information. the
Administrator has no balis to
reconsider hil rIDding that the
prescribed emislion limitations are
achievable on modem boilers produced
by all four major manufacturers.
VI Emission Measurement and
Compliance Determination
The Utility Air Regulatory Group
(UARG) raised several issues pertaining
to the accuracy and reliability of
continuoul monitors used to determine
compliance with the SO. and NO.
standardl. UARG particularly
commented on the data from the
Conesville Station. In addition. they also
maintained that the sampling method for
particulatel was flawed. With respect to
compliance determinations. UARG
maintained that the method for
calculating the 3G-day rolling averages
should be changed .0 that emissionl
before boiler outagel are not included
since they might bias the results. In
addition. UARG argued that the
standardl were Oawed since EPA had
not included a statement al to how the
Agency would conaider monitoring
accuracy in relation to compliance
determination. With the exception of the
method of calculating the 3O-day rolling
average and the comments on the
Conesville station. the petition merely
reiterated commen.. submitted prior to
the close of the public comment period.
As to the reliability and durability of
continuoul monitors. Information in the
docket (OAQPS-78-1. II-A-88. IV-A-20.
IV-A-21. and IV-A-22) demonstrates
that on-site continuous monitoring
systems (CMS) are capable and have
operated on a long-term basis producing
data which meet or exceed the minimum
data requirements of the standards.
In reference to the Conesville project,
UARG questioned why EPA dismissed
the continuous monitoring results since
it was the only long-term monitoring
effort by EPA to gain Instrument
-------
Federal Register / Va\. 45. No. 26 / Wednesday. February 6. 1980 / Rules and Regulations
8231
operating experience. UARG maintained
that this study showed monitor
degradation over time and that it was
representative of state-of-the-art
monitoring system performance. This
conclusion is erroneous. EPA does not
consider the Conesville project adequate
for drawing conclusions about monitor
reliability because of problems which
occurred during the project.
To begin with. UARG is incorrect in
suggesting that the goal of the project
was to obtain instrument operating
experience. The primary purpose of the
project was to obtain 90 days of
continuous monitoring data on FGD
system performance. Because of
intermittent operation of the steam
generator and the FGD system. this
objective could not be achieved. As the
end of the 9O-day period approached. a
decision was made to extend the test
duration from three to six months. The
intermittent system operation continued.
As ° result. when the FGD outoges were
deleted from the total project time of six
months. the actual test duration was
similar to those at the Louisville.
Pittsburgh. and Chicago tests and did
not. therefore. represent an extended
test program.
EPA does not consider the Conesville
results to be representative of state-of-
the-art monitoring system performance.
Because of the intermittent operation
throughout the test period (OAQ~78-
1. IV-A-19. page 2). it became obvious
that the goals of the program could not
be met. As a result. monitoring system
maintenance lapsed somewhat. For
example. an ineffective sample
conditioning system caused differences
in monitor and reference method results
(OAQP~78-t. IV-A-20. page 3-2). If the
EPA contractor had performed more
rigorous quality assurance procedures.
such as a repetition of the relative
accuracy tests after monitor
maintenance more useful results of the
monitor's performance would have been
obtained. Thus. the Conesville study re-
emphasized the need for periodic
comparisons of monitor and reference
method data and the inherent value of
sound quality assurance procedures.
The UARG petition suggested that the
standards incorporate a statement as to
how EPA will consider monitoring
system accuracy during compliance
determination. More specifically. UARG-
recommended that EPA define an error
band for continuous monitoring data
and explicitly state that the Agency will
take no enforcement action if the data
fall within the range of the error band.
The Agency believes that such a
provision is inappropriate. Throughout
this rulemaking. EPA recognized the
need for continuous monitoring systems
to provide accurate and reproducible
data. EPA also recognized that the
accuracy of a CMS is affected by basic
design principals of the CMS and by
operating and maintenance procedures.
For these reasons. the standards require
that the monitors meet (1) published
performance specifications (40 CFR Part
60 Appendix B) and (2) a rigorous
quality assurance program after they are
installed at a source. The performance
specifications contain a relative
accuracy criterion which establishes an
acceptable combined limit for accuracy
and reproducibility for the monitoring
system. Following the performance test
of the CMS. the standards specify
quality assurance requirements with
respect to daily calibrations of the
instruments. As was noted in the
rule making (44 FR 33611. right column),
EPA has initiated laboratory and field
studies to further refine the performance
requirements for continuous monitors to
include periodic demonstration of
accuracy and reproducibility. In view of
the existing performance requirements
and EPA's program to further develop
quality assurance procedures. the
Administrator believes that the issue of
continuous monitoring system accuracy
was appropriately addressed. In doing
so. he recognized that any questions of
accuracy which may persist will have to
be assessed on a case-by-case basis.
The UARG petition also raised as an
issue the calculation of the 30-day
rolling average emission rate. UARG
maintained that the use of emission data
collected before a boiler outage may not
be representative of the control system
performance after the boiler resumes
operation. UARG indicated that boiler
outage could last from a few days to
several weeks and suggested that if an
outage extends for more than 15 days. a
new compliance period should be
initiated. UARG also suggested that if a
boiler outage is less than 15 days
duration and the performance of the
emission control system is significantly
improved following boiler start-up. a
new compliance period should be
initiated. UARG argued that the data
following start-up would be more
descriptive of the current system
performance and hence would provide a
better basis for enforcement.
A basic premise of this rulemaking
was that the standard should encourage
not only installation of best control
systems but also effective operating and
maintenance procedures (44 FR 33595
center column. 33601 right column. and
33597 right column). The 30-day rolling
average facilitates this objective. In
selecting this approach. the Agency
197
recognized that a 30-day avera~;p. hettl'r
reflects the engineering realIties uf SU,
and NO, control systems since it ~ff,mJs
operators time to identify and res[Juf'd
to problems that affect control sys'el~l
efficiency. Daily enforcement [roll.:l'~
average) was specified in order to
encourage effective operating ,lnd
maintenance procedures. Under this
approach. any improvement in em1SSIun
control system performance following
start-up will be reflected in the
compliance calculation along with
efficiency degradations occurring before
the outage. Therefore. the 30-day roll:n~
average provides an accurate picture of
overall control system performance.
On the other hand. the UARG
suggestion would provide a distorted
description of system performance since
it would discount certain episodes of
poor control system performance. That
is. the system operator could allow the
control system to degrade and then shut-
down the boiler before a violation of the
standard occurred. After start-up and
any required maintenance. a new
compliance period would commence.
thereby excusing any excursions prior to
a shut-down. In addition. since a new
averaging period would be initiated the
Agency would be unable to enforce the
standard for the first 29 boiler opera ting
days after the boiler had resumed
operation. In the face of this potential
for circumvention of the standards. the
Administrator rejects the UARG
approach.
UARG also reiterated their previuus
comments that EPA did not properly
consider the accuracy and precision of
Reference Method 5 for measuring
particulate concentrations at or below
13 ng/) (0.03 Ib/million Btu] heat input.
EPA has recognized throughout this
rulemaking that obtaining accurate and
precise measurements of very low
concentrations of particulate mallf'r IS
difficult. In view of this. detailed ~:ld
exacting procedures for the clean-up
and analyses of the sample probe- fliter
holder. and the filter were specified in
Method 5 to assure accuracy in
determining the mass collected.
Additionally. EPA has required tholt :he
sampling time be increased from 60
minutes to 120 minutes. This will
increase the total sample volume from a
minimum of 30 dsd to 60 dsd. thus
increasing the total mass collected 10
about 100 mg at a loading of 13 ngIJ
(0.031b/million Btu) heat input. EP-\ holS
concluded that measurement of mass ~t
this level can be reproduced witillil .::::0
percent.
UARG also maintained that les, :h,Jn
ideal sampling can cause particula:e
emission measurements to be ir..1c~ur,jle
-------
8232
Federal Register / Vol. 45, No. 26 / Wednesday, February 6. 1980 / Rules and Regulations
and thIs has not been evaluated. EPA
has addressed the question of
determining representative locations
and the number of sampling points in
some detail in the reference methods
a[)d appropriate subparts. These
procedures were designed to assure
accurate measurements. EPA has also
evaluated the effects of less than ideal
samphng locations and concluded that
generally the results would be biased
bf'loIV actual emissions. Assessment of
the extent of possible biases in
measurement data, however. must be
made on a case-by.case basis.
UARG raised again the issue of acid
mIst generated by the FGO system being
calk, ted in the Reference Method 5
'dmple. therefore rendering the emission
limit unachievable. EPA has recognized
this problem throughout the rulemaking.
In rps1Jonse to the Agency's own
findin~s and the public comments. the
standards permit determination of
particulate emissions upstream of the
scrubbf'r. In addition, EPA announced
Ihat it IS studying the effect of acid mist
on particulate collection and is
developing procedures to correct the
collected mass for the acid mist portion.
1/11 Applicability of Standards
Sierra Pacific Power Company and
Idaho Power Company (collectively,
"Sierrd Pacific") petitioned the
Administrator to reconsider the
dpfinltion of "affected facility," asking
thd' the applicability date of the
standards be established as the date of
promulgation rather than the date of
pn1posal. 40 CFR 6O.40a provides:
ra I The affected facility 10 which Ihis
sllhp.lrt applies is each electnc utility steam
gener,l'ln~ Unit:
(21 ror which construction or modification
"r"",."pnced after September 18. 1978.
~I'r'!'mber 19. 1978. is the date on
\\ h,ch the proposed standard was
publbhed in the Federal Register. EPA
based Ihis definition on sections
111(a112) and 111(b)(6) of the Act.
SectIOn 111(a)(2) provides:
Thr 'erm "new source" means any
st;!11t . -.ry source. the construction or
mod:' "lion of whIch is commenced after the
pub\: Ion of regulations (or. ,f earlier,
prop, i regulations) prescribing a standard
uf ppr:e mance under this section which will
bp ar'pilcable to such source.
Sf'Ltlon 111(b)(6) includes a similar
provIsIOn specIfically drafted to govern
th., ,trphcabllity date of revised
sl.lIld"rds for fossil. fuel burning sources
lof \\ hll:h this sfand,ud is thl' chief
..",mple) It pro\ Ides:
Am new or modified f08s,I fuel-fired
slatlonilry source which commences
construction prior.lo the dale of publication
of Ihe proposed revised standards shall nol
be required to comply with such revised
standards.
Sierra Pacific does not dispute that
the Agency's definition of affected
facility complies with the literal terms of
sections 111(a)(2) and 111(b)(6). Sierra
Pacific maintains, however, that the
definition is unlawful. because the
standard was promulgated more than 6
months after the proposal. in violation of
sections l11(b)(l)(B) and 307(d)(10).
Section l11(b)(l)(B) provides that a
standard is to be promulgated within 90
days of its proposal. Section 307(d)(10)
allows the Administralor to extend
promulgation deadlines. such as the 90-
day deadline in section l11(b)(l)(B), to
up to 6 months after proposal. Sierra
Pacific argues that section 111(a)(2) does
not apply unless the deadlines in
sections 111(b)(1)(B) and 307(d)(10) are
met. In this case the final standard was
promulgated on June 11, 1979, somewhat
less than 9 months after proposal. (It
was announced by the Administrator at
a press conference on May 25. 1979, and
signed by him on June 1. 1979.)
In the Administrator's view, the
applicability date is properly the date of
proposal. First. the plain language of
section 111(a)(2) provides that the
applicability date is the date of
proposal. Second. the legislative history
of section 111 shows that Congress did
not intend that the applicability date
should be the date of proposal only
where a standard was promulgated
within 90 days of proposal. Section
111(a)(2) took its present form in the
conference committee bill that became
the 1970 Clean Air Act Amendments.
whereas the 9O-day requirement came
from the Senate bill. and there is no
indication that Congress intended to link
these two provisions.'
Moreover, this interpretation
represents longstanding Agency
practice. Even where responding to
public comments delays promulgation
more than 90 days. or more than 6
months. after proposal. the applicability
dates of new source performance
standards are established as the date of
proposal. See 40 CFR Part 60. Subparts
o et seq.
Sierra Pacific argues that its position
has been adopted by E?t, in
"analogous" circumstances under the
Clean Water Act. This is inaccurate.
Section 306 of the Clean Water Act
specifically provides that the date of
! In amy l'\ t"nl In the Admmislrator'! vU'W the 9O~
d.JY requlu'mt"nt In secllon 111{bJ(1J(D) no IORMer
go\'erns the promulRiition or r8\"510n of new source
,t.lndard. It has been replaced by procedurt"s set
forlh '" .ocllon 111(fj en.clod by ,ho 1977
amendments
198
proposal of a new source standard is the
applicability date only if the standard is
promulgated within 120 days of proposal
(section 306(a)(2). (b)(1)(B)).
Sierra Pacific suggests that utilities
are "unfairly prejudiced" by the
applicability date. but does not submit
any information to support this claim. In
any event. there does not seem to be
;any substantial unfair prejudice. At the
time of proposal. the Administrator had
not decided whether a full or partial
control alternative should be adopted in
the final SO. standard. As a result. the
Administrator proposed the full control
alternative stating (43 FR 42154, center
column):
. . . the Clean Air Acl provides Ihat new
source performance Ilandards apply from the
date they are propoled and it would be easier
for power plants Ihal II art conslruction
during the proposal period 10 scale down to
partial control than to scale up 10 full conlrol
should the final standard differ from Ihe
proposal.
In facl. the final SO. standard was less
stringent than the proposed rule.
In this case. utilities were on notice on
September 19. 1978, of the proposed
form of Ihe standard. and that the
standard would apply to facilities
constructed after that date. In March
1979, it became clear to the Agency that
it would not be possible to respond to
all the public comments and promulgate
the final standards by March 19, as
required by the consent decree in Sierra
Club v. Castle. a suit brought to compel
promulgation of the standard. (The
comment period had only closed on
January 15; EPA had received over 625
comment letters. totalling about 6.000
pages. and the record amounted to over
21.000 pages.) The Agency promptly
contacted the other parties to Sierra
Club v. Costle, and all the parties jointly
filed a stipulation that the standand
should be signed by June 1 and that the
Administrator should not seek "any
further extensions of time." This
stipulation was well-publicized (see. for
example. 9 Environment Reporter
Current Developments 2246, March 30,
1979). Thus utili lies such as Sierra
Pacific had reasonable assurance that
the standard would be signed by June 1.
as it was.
Even assuming. as Sierra Pacific does,
that section 111 required the standard to
be promulgated by March 19. ulilities
had to wait only an additional period of
84 days to know tl)e precise form of the
promulgated standard. This delay is not
substantial in light of the long lead limes
required to build a utility boiler. and in
light of the fact that the pollution control
techniques required to comply with the
promulgllted standard are substantially
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..
Federal Register I Vol. 45, No. 29 I Monday, February 11. 1980 I Notices
9101
Enforcement PoDcy for Sutphur
Dioxide Emission Umltatlona In Ohio
The United States Environmental
Protection Agency is announcing a
policy concerning sulfur dioxide
emission limitations in Ohio. This policy
amends those previously announced on
February 15. 1978 (43 FR 6646) and
August 22, 1979 (44 FR 49296).
The promulgated sulfur dioxide
implementation plan requires subject
sources to achieve specified emission
limitations and demonstrate compliance
using test methods specified in 40 CFR
Part 60. U.S. EPA has initiated a review
of its policies and procedures for
regulating sulfur dioxide emissions from
coal.fired plants and has addressed the
question of sulfur variabilitv in that
context. As part of this review, U.S. EPA
has announced intention to propose
policy and regulatory changes which
would permit states to analyze the air
quality impact of variable sulfur
emissions in their attainment
demonstrations. Since changes to the
rules and policies are required for the
new evaluation technicuqe. a final
determination on the acceptability can
only be made after public comments on
the policies are reviewed and final
decisions are published.
In the interim, while the sulfur
variability issue is under review, the
Agency will focus its enforcement
resources on those plants which present
the greatest environmental threat. While
the State of Ohio is re-evaluating the
emission limitations in a manner
consistent with U.S. EPA's proposed
policy and is proceeding with a coal
washing program for high sulfur coal.
U.S. EPA will give enforcement priority
to those plants in Ohio which fail to
meet certain conditions which are listed
below. This policy will. in effect. mean
for the next year that U.S. EPA will not
initiate SO. enforcement actions in Ohio
against sources which satisfy the
following conditions:
199
(a) The source is meeting the currently
applicable. promulated SO. emissIOn
limits applied as a 3O-day rolling,
weighted average.
(bJ The source obtains daily
information on SO. emiSSions through
use of in-stack monitors or fuel sampling
and analysis techniques as set furth In
40 CFR Part 60 and makes Ihls
Information available to the State and
the U.S. EPA upon request.
(c) The emissions of SO. in anyone
day do not exceed 1.5 limes the
emission limit in the currently
applicable SIP.
Any source failing to meet all these
conditions will be subject to
enforcement of the regulations as
originally promulgated.
Dated: February 5. 1980
John McGuire.
RegIOnal Admlnlstator. R"!Jlon V.
I~ Doc 8C).....4l90 Fili!d 2-8-&1 e -15 .lmJ
BILLING CODE I~'-"
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999-l
Federal Register' Vol. 45. No. 32 , Thursday, February 14. 1980 I Notices
9995
Regulation of Large Coal-Fired Boilers
for S0, Emissions
AGENCY: U.S. Environmental Protection
Agenc y
ACTION: No ti ce.
SUMMARY: The purposes of this Notice is
to advise the public that EPA has
imlldled a review of policies and
procedures for regulating large coal.fired
boilers and to invite comment on the
results of that re\ lew. Included are
preliminary positions on gUidelines for
met£'rologlcal dispersion models:
guidl,j,nes on regulatory development
\\ Ilh emphasIs on averaging times. the
use of a statistical technique for
e\ aluatlng variable emissions. and
accelerated installation of in.slack
monitors and their use in future SIP
modJl.catlOns as the reQUired
comp!'dnce method. Some 01 the
antlci"ated changes will involve
rulemdking; others will involve changes
to procedural guidelines or policy
announcements. There will be
oppurl unity for public comments on
each Involvement by many mterests is
encouraged because of the potential
impacts of these changes on acid
prec1pltatlOn, visibility, coal utilization
and the cost of power production. This
Notice IS intended to provide an
0\ erview of the program since its
impl,'mt'ntation will require a number of
Sep;lfJle administrative actions.
BACKGROUND: The United States
Environmental Protection Agency has
imtld"',j 8 program to revise the rules
and policies applicable to controlling
sulfur emissions from coal.flred power
plants. Information developed over the
past s,'\Cral years has made it
In, fI' ,,,ngly apparent that hl5torical
",,'!Lod, 01 estimating impacts and
,,,Idbl,,hing emission limits for power
pl.ltll> arc not adequately defined and
are not being applied conslstenlly In
"je!",,'n, current emission monitoring
and 1,.r,HcI'ment techniques have been
foane! 1o be cumbersome and ineffective
The Clean Air Act provides for the
eSlauhhment and attainment of
8ml.JJ('~: standards which will provide
an "4" .J measure of health and welfare
pwl,. .n to residents of e\'ery State.
1 hi' S' ,dards for sulfur dio...ide require
tholt an, lenl concentrations, averaged
annu.d', and over 24 hour and 3 hour
p"rlod" not e...ceed specified levels.
Assuring attainment of the standards in
tlll' \" inity 01 power requlrl's an
undl'r!ot,tndlng 01 the ground It'\el
conrl'ntrallOns e'-pecled to result from
thl' pl.,nl's emissions under the
mr.!rrological conditions observed in thp
aff, [ll'd arpa Estimates of £round level
concentrations are developed through
the use of mathematical dispersion
models which predict concentrations
associated with given emission rates
and meterological conditions. These
predictions a re used to develop emission
Ilmllations which will protect against
violations of the standard.
All mat"ematical simulations models.
whe:hl'r they are of industrial processes.
economic systems or phyi~cal events,
contain estimates and assumptions
which can only approximate real world
conditions. Similarly, translation of
inlurmation gl'nerated by models into
m;tnagl'ment decisions or emission
limits requires a series of policies and
procedures to reduce the possibility of
undesired consequences which might
rpsult from errors in predictions. In the
dl'vclopment of emission limits for
power plants. regulatory policies must
pro\'ide for adequate protection of the
ambient standards despite uncertainty
in predicted air quality impacts.
A major area of inconsistency in the
application of model results to power
pl.tnt emission limits has been the
treatment of natural variations in the
sulfur content of coal. Coal. even from
the same mine, will vary in sulfur
content. from day to day. Sulfur dioxide
emissions will vary with changes in
sullur content. making daily air quality
impacts difficult to estimate. Sulfur
varabillty was not well understood by
either industry or the government when
initial rules were developed by the
States. As a result, it was generally
ignored when most emissions limits
were established. This has caused
substantial problems in the
interpretation and enforcement of
existing rules as well as in the transition
to the more explicit regulations now
being required by the Agency..
Another problem area involves the
development of emission limits which
protect the standard given the fact that
model results are only estimates and
may either underpredict or overpredicl
actual concentrations. An
underprediction could result in emission
limits that do not provide the
appropriate degree of assurance that
ambient standards will be protected.
Over the past ten years ground level
concentrations for SO. have been
reduced in many area~ P"1d most of the
remaining problems are associated with
power plants and smelters which have
not come into compliance with existing
emission limits. The modifications being
proposed by the Agency are necessary
to insure that the remaining sources can
be brought into compliance through
effective enforcement; to provide a clear
policy for evaluating new sources; and
to resolve issues which are delaying the
development of State rules for those
sources requiring additional contr.ol.
200
While the current program has
substantially reduced the problems of
localized effects of sulfur oxides. there
is a large and possibly more significant
threat to the environmental posed by
emissions of sulfur compounds to the
atmosphere. Acid precipitation resulting
from region-wide emissions of sulfur
and nitrogen compounds threatens our
lakes and forests and those of Canada.
Since the Clean Air Act was designed 10
deal primarily with ground level
concentrations in the vicinity of
individual sources. it offers only limited
tools to deal with broad regional
problems such as acid rain.
A reduction in acid precipitation will
require reductions in emissions over
broad geographic regions. While there
are a number of alternatives for
accomplishing such a reduction, the
most promising near-term measure
appears to be increased cleaning of high
sulfur coal, through coals washing
techniques. A program to require coal
cleaning of high sulfur coals has been
advocated by one State (Ohio) and EPA
believes that similar actions in other
States would provide a real and
signil1cant benefit. Therefore, the
policies to be proposed by the Agency
will encourage States and sources to
increase the use of washed coal. While
the alternatives considered by the
Agency in the review of policies and
procedures for coal-flfed boilers will
move toward reductions in total
emissions of sulfur oxides from current
levels, they cannot be expected to
reduce atmospheric loadings sufficienfly
to solve the acid precipitation problem.
Significant reduction in regional
emission of SO. will require legislative
changes.
Proposed Actions
The actions contemplated by the
Agency include revisions to: (1)
Enforcement programs. with emphasis
on emission data and methods 01
determining compliance.
(2) Guidelines for dispersion
modeling.
(3) Guidelines for developing emission
limits for State Implementation Plans
(SIPs) with emphasis on averaging
times. variability in SO. emissions, and
certainties in modeling estimates.
ENFORCEMENT DATA: Effective
enforcement of regulations for sources
with varying emissions, such as coal-
fired boilers. depends strongly on the
routine availability of emission data, On
August 8, 1979, EPA published an
Advance Notice of Proposed
Rulemaking "Emission Monitoring of
Statlbnary Sources" (40 crn Parts 51
and 52. Vol. 44. No. 154). The schedule
published for promulgating regulations
requiring the installation of continuou~
Ill-stack monitors will be accelerated for
coal-fired boilers and broadened to
-------
9995
Federal Register I Vol. 45. No. 32 I Thursday. February 14. 1980 I Notices
9996
include periodic coal sampling or more
frequent stack sampling for some units
in order to provide information
necessary to ensure compliance with
existing emission limits.
In addition. it is apparent that the
manual stack test methods usually
required in existing regulations
generally do not provide adequate data
for effective enforcement. Therefore. the
Allency will propose a change to Part 51
I.!t40 CFR requiring that continuous in.
stack monitoring or periodic coal
samDlinj! hp. the only ar.ceDtable
compliance method lor SU, in all future
SIP modification~ involvinillarge coal-
fired boilers.
MODELING GUIDELINES: Dispersion
models are used to predict the ground
level air quality impacts of power plant
emissions. While the models used are
consiste"nt in basic design.-their
application requires a number of
assumptions and variety of data about
emissions. background concentrations
and weather conditions. EPA proposed.
took comment on and published in 1978
a report "Guidelines on Air Quality
Models" (EPA-450/2/7B-<127) in order to
provide formal guidance on the
application of these models. However.
this report provides substantial
flexibility to the user. The Agency now
proposes to tighten this guidance to
establish specific data requirements.
Included will be a requirement that five
years of meteorological data be used to
insure representativeness of results. a
requirement that the plant be modeled
at the lo'ad which would identify the
highest ground level concentration. and
more specific requirements for
identifying critical receptor sites. The
combination of these actions should
improve the consistency and accuracy
of model applications for future
regulations.
GUIDELINES FOR DEVELOPMENT OF
EMISSION LIMITS: There does now exist a
formal set of guidelines for developing
regulations from modeling data. This has
been an important cause of
inconsistency and possibly ambiguity in
some existing SIP emission limits for
coal-fired boilers. Therefore. a set of
guidelines will be proposed early in 1980
to assist States and EPA Regions in
setting emission limits.
The most difficult problem to be
addressed will be the considera tion of
coal sulfur variability in- the
establishment of emission limits. In the
past the Agency has advocated an
assumption that emissions would be
uniform at the maximum coal sulfur
contenl and required that regulations be
established to protect against maximum
emissions under all weather conditions.
A number of States and industries have
requested that the Agency review this
polIcy and consider an alternative of
allowing longer (30 day) averaging times
in emission limits. They argue that the
term average better represents actual
operating conditions and potential
ambient impacts.
While the Agency agrees that coal
sulfur variability cannot be ignored. it
has been and continues to be unwilling
to accept the 30-day average proposals
as adequate to demonstrate protechon
of the ambient standards or as an
appropriate form for insuring
compliance. Accordingly. the Agency
will propose for comment an alternative
technique which uses statistical tools to
analyze the probabilities of significant
air quality impacts under conditions of
varying emissions. When combined with
appropriate meteorological data.
continuous in-stack monitoring and
emissioulimlts specification, this
technique appears to provide an
appropriate mechanism to consider coal
sulfur variability.
The statistical model will be proposed
as a permissible alternative where the
following conditions are met:
a. Five years of meteorological data
are employed in the model and worst
case load conditions are considered.
b. Compliance is determined throul!h
the use of in-stack monitors or daily coal
samDles.
c. Emission limits are specified at a
minimum both for a 24 hour averaging
period and a 30-day rolling averaging
period.
d. High sulfur coal will be washed to
reduce both sulfur content and
variability, thereby reducing the
potential for short-term exceedances.
The guidelines also will specify
selection of an acceptable degree of
certainty of attainment for use with the
statistical technique and values for
sulfur variability if plant.specific data
are not available. Policies applicable to
emission limits for coal-fired boilers in
other situa tions also will be proposed.
These will include smaller urban point
sources and plants in complex terrain
where only screening-type diffusion
models are a\'ailable for use.
The problem of uncertaiDty in model
predictions also will be addressed and
may lend itself to the application of a
similar statistical technique. In this case
statistical tools would be used to
determine the probability that a model
has underpredicted ground level
concentrations for a given application
and that as a result actual
concentrations would exceed the
standard. While more work has been
done to date on the application of
statistical te~hniques to sulfur
201
variability. the Agency's review of
modeling and regulatory policies will
extend to the problem of possible
underpredication and the proposal of
appropriate corrective action.
\! must be emphasized that this Notice
is being published only as general
information to illustrate the scope of the
review and to present the Agency's
rationale and initial conclusions ir. a
comprehensive package. This Notice
should not be interpreted as a license to
implement any of the changes being
discussed. Each will be proposed In a
more formal manner, announced or
proposed in the Federal Register with
opportunity for comment and made final
as a modification to the appropria te
Agency policy, guidelines or regulation.
Accordingly, this Notice does not affect
EPA's November 7.1979, proposal 10
approve emission limitations for two
West VirgInia power stations. where a
statistical analysis of fuel variability
was combined with an alternative set of
more stringent conditions in determining
that a violation of ambient air quality
standards was not expected (44 FR
64439).
CommeDts and AdditionallnIormation
The series of possible changes to
regulations. guidelines, and policies for
evaluating coal-fired boilers outllIled in
this notice have the potential for
widespread impact. These include effect
of acid precipitation and on productivity
of lakes and forests. visibility, impact of
sulfates on public health, ability to
utilIze coal as an energy source. chJngf's
in patterns of coal supply and
employment in the mining industry and
cost of electricity. Because of tht~ EPA
will provide extensive opportunity for
review and public comments as each
segment of the overall program is
proposed and moves toward final
decision and implementation.
EPA also welcomes general comment
at this time on the concepts and overall
program described in this notice.
Comments and suggestions should be
sent to B. ). Steigerwald, Environmental
Protection Agency (MD-tOl. ReseJrch
Triangle Park, N.C. 27711. Phone (919)
541-5256.
Dated: February 5. 1980.
Barbara Blum,
Admin/slreluF.
-------
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Wednesday
February 20, 1980
Part IV
Environmental
Protection Agency
Draft Performance Specification 4-
Specifications and Test Procedures for
Carbon Monoxide Continuous Monitoring
Systems In Stationary Sources
203
-------
11-144
Federal Register / Vol. 45. No. 35 / Wednesday. February 20. 1980 / Propo8ed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
IFRl1389-2)
Standards of Performance for New
Stationary Sources Continuous
Monitoring Performance
Specifications
AGENCY: Environmental Protection
Agency (EPA). .
ACTION: Advance notice of proposed
rulemaking.
SUMMARY: This notice sets forth draft
Performance Specification 4-
SpecIfications and Test Procedures for
Carbon Monoxide Continuous
\lomtonng Systems in Stationary
Sources. which EPA is considering to
propose as an addition to Appendi~ B of
40 CFR Part 60. The intent of this
advance notice IS to solicit comments on
the specifications and testing
procedures EPA is considering.
ThIs advance notice of proposed
rulemaking is issued under the authority
of Sections 111. 114. and 301(8) of the
Clean Air Act as amended (42 U:S.C.
7411, ~414. and 7601(a)).
DAns: Written comments and
Informal1on should be post-marked on
or before May 20. 1980.
ADDRESSES: Comments. Written
comments and information sbould be
submItted (in duplicate. if possible) to:
Central Docket Section (A-130).
AttentIOn: Docket Number A-79-{)3. U.S.
Environmental Protection Agency. 401 M
Street. SW.. Washington. D.C. 20480.
Docket. Docket Number A-79-{)3.
containing material relevant to this
rule making. IS located in the U.S.
Environmental Protection Agency
Central Docket Section. Room 2903B. 401
\1 Street. SW.. Washington. D.C. 20460.
The Jocket may be inspected between
8.00 a m. and 4:00 p.m. on weekdays.
dnd a reasonable fee may be charged for
cr'PYlng.
FOR F1JRTHER INFORMATION CONTACT:
\lr. Don Goodwin (MD-13), U.S.
Environmental Protection Agency.
RrseJfch Tnangle Park. N.C. 27711.-
lel!'r> one (919) 541-5271.
supr 'MENTARY INFORMATION: EPA -
proIT, ,ated standards of performance
for n-" stationary sources pursuant to
Sec;"f 111 of the Clean Air Act. as
amenJed, on March 8.1974 (39 FR 9308).
:Gr petroleum refineries and SIX other
Sla I""!lar\' sources. New or modIfied
-" ..-:~g ;n 'hese categones are required
'0 derr'mstrate compliance with the
'_r:,~,j"rds of performance by means of
performance tests that are conducted at
the time a new source commences
operation or shortly thereafter. To
ensure tbat these sources are properly
operated and maintained so as to
remain in compliance. provisions were
included in the standards that require
sources to install and operate a
continuous emiSlion monitoring system.
'One sucb requirement was for carbon
monoxide (CO) from petroleum
refineries.
When the standards were initially
proposed. EPA had limited knowledge
about the operation of continuous
monitora on such sources: thus. the
continuous emission monitorins
reqUirements were specified in general
terms. Additional guidance on the
selection and use of sucb instruments
was to be provided at a later date.
On October '6. 1975 (40 FR 48259). the
Environmental Protection Agency
amended Part 60 of the resuJations by
addins Appendix B-Performance
Specifications 1. Z. and 3 for continuous
monitoring of (!topacity. (2) sulfur
dioxide and nitrosen oxide. and (3)
oxygen or car.bon dioxide. respectively.
Performance specifications for CO
monitora were not published at thai
time.
EPA has conducted short-term
evaluations of tbe applicability of
several continuous monitorin.
instnnnents and has published the
results in the followin. documents:
Guidelines lor Dt1ve/opment 01 a Quality
Assurance program: Volume VIII-
Detennination of CO Emission. from
Stationory Sources by NDIR
Spectrometry. EPA~/4-74-005-h
(February 1975); and Evaluation 01
Continuous Monitors lor Carbon
Monoxidt1 in Stationary Sources. EPA-
6OO/.z-77-063) March 1977). Both are
available through the National
Technical Information Service.
Springfield. Virginia 22161.
Based "In the above documents.
specificstions and test procedures were
drafted for continuous CO monitorins
instruments. the format of the draft
Performance Specification 4 follows
closely that of the most recent proposed
revisions to Performance Specification 2
(44 FR 58602 dated Oct. 10. 1919).
Several references are made in
Performance Specification 4 to specific
sections of the Perform 3 I'! :1'
Specification 2 revisions.
The Environmental Monitorins and
Support Laboratory of EPA is also
presently conductins a laboratory and
long-term field study of CO continuous
mom toring systems. Results of this
study will provide essential background
and technical information In support of
or Improvement to Performance
204
Specification 4. The completio!' date is
scheduled for mid-1961. For this reason.
Performance Specification 4 for CO is
published as an advance notice.
Specific Requeata
EPA is requesting c0n:tments on the
attached draft Performance
Specification 4-Specifications and Test
Procedures for CO Monitoring Systems
in Stationary Sources. EPA Is interested
In comments on altematives to the
performance specifications and is
particularly interested in information
that could lead 10 the development of
improved or aItemative procedures. EPA
is also interested in comments on the
followinS aspects of CO continuous
monitoring and Performance
Specification 4: (1) Estimates of
installation and operation costs
including equipment costs. manpower
requirements. data reduction options.
and maintenance costs. (2) procedures
applicable for the evaluation of sinsle-
pa88. in-situ monitorins system: (3)
laboratory teslin. procedures that are
nece88ary for determining monitoring
system performance acceptability and
those laboratory tests that can be
recommended as indications of the
quality of equipment operation; (4) the
specifications and limit8 set forth in
Section 4; (5) the applicability of
Reference Method 10 or other methods
for determining relative accuracy of
continuous CO monitoring systems.
Dated: February 12. 1980.
Barbera BIUIII,
Actina Admini.trator.
Performance Specification 4-
Specifications and Test Procedures for
Carbon Monoxide Continuous
Monitoring Systems in Stationary
Sourcea
1. Applicability and Principle
1.1 Applicability. This specification
contains (a) installation requirements.
(b) instrument performance and
equipment specifications. and (c) test
procedures and data reduction
procedures for evaluating the
acceptability of carbon monoxide (CO)
continuous monitorins systems. The test
procedures are not applicable to single-
paIS. in-situ monitoring systems: these
systems will be evaluated on a case-by-
case basis upon application to the
Administrator. and aItemative
procedures will be ilSued separately.
1.2 Principle. A CO continuous
monitoring system that is expected to
meet this specification is installed.
calibrated. and operated for a specified
length of time. During the specified time
period. the continuous monitoring
-------
Federal RegiBter I Vol. 45. No. 35 I Wednesday. February 20. 1980 I Proposed Rules
114-15
system is evaluated to determine
conformance with the specification.
2. Definitions
The definitions are the same as those
listed in Section 2 of Performance
Specification 2.
3." Installation Specifications
Install the continuous monitoring
system at a location where.the ponutant
concentration' measurements are
representative of the total emissions
from the affected facility. Use a point.
points. or a path that represents the
average concentration over the cross
section. Both requirements can be met
as follows:
3.1 Measurement Location. Select an
accessible measurement location in the
stack or ductwork that is at least two (2)
equivalent diameters downstream from
the nearest CO control device or other
point at which a change in the pollutant
concentration may occur and at least 0.5
equivalent diameter upstream from the
exhaust. Individual subparts of the
regulations may contain additional
requirements.
3.2 Measurement Point. or Paths.
The tester may choose to use the
following measurement point. points. or
path without a stratification check or he
may choose to conduct the str.atification
check procedure given in Section 3.3 of
Performance Specifi~ation 2 to select the
point. points. or path of average gas
concentration.
3.2.1 CO Path Monitoring Systems.
Same as in Performance Specification 2.
Section 3.2.2.
3.2.3 Single-Point and Limited-Path
Monitoring Systems. Same as in
Performance Specification 2. Section
3.2.3.
4. Performance and Equipment
Specifications
The continuous monitoring system
performance and equipment
specifications are listed-in Table 4-1. To
be considered acceptable. the
continuous monitoring system must -
demonstrate compliance with these
specifications using the test procedures
of Section 6.
5. Apparatus
5.1 Continuous Monitoring System.
Use any continuous monitoring system
for CO. which is expected to meet the
specifications in Table 4-1. The data
recorder may be an analog strip-chart
recorder or other suitable device with an
input signal range compatible with the
analyzer output.
Table "'I.-COntinuous MoMonng System
PerlotmIIncs and EqlJlfJment SpsctficatJOM
P.........
Speofica-
,. CondrtIonir1g -. .n. l 168 -
2. Opora- ,... l HIli -
3. =tion....,. - ~ s - of oacn --- -
~ ---
.. R- -.--- ~ '0.........
5. Z...,drtII,21101n'.-.. ~ '_01_-
8. Z""'drtft.2. 1IoIn'- ~2_of_.-
7. CaIoIntIan alii, 2 ~ 2 - of --
1IoIn'.
8.~drtft.2.
haura '.
I. R_'" 1ICCIr8CY' -- :; '0 - of - ReI. -
10. CaIoIntIan 8M COllI - provod8 a - of II .".
..- 1yBr----
- .. - arcutry ...
dudinilthe -- -- -
........ -.Illy. """'" ...
.........., - .. ........ -
......,..
1,. Data - cIW1 CI1ar1 -- ..... be - II>
.-. -: 0.5_offull.
......
~2.5_of_-
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-.....-... - - not -.n any..,..."....
-- ~ .. .......... - IIwI -
~ ~......... and...- in the ---
- ......-
.~. un of - --.- pM 95 110"
..._-"'a_--tlya_.
.... .-
5.2 Calibration Gases. For
continuous monitoring systems that
allow the introduction of calibration
gases to the analyzer. the calibra tion
gases must be CO in N.. Use three
calibration gas mixtures as specified
below:
5.2.1 High-Level Gas. A gas
concentration that Is.equivalent to 80 to
90 percent of the span value.
5.2.2 Mid-Level Gas. A gas
concentration that Is equivalent to 45 to
55 percent of the span value.
5.2.3 Zero Gas. A gas concentration
of less than 0.25 percent of the span
value. Prepurified nitrogen should be
used.
5.3 Calibration Gas Cells or Filters.
For continuous monitoring systems
which use calibration gas cells or filters.
use three certified calibration gas cells
or filters as specified below:
5.3.1 High-Level Gas Cell or Filter.
One that produces an output equivalent
to 80 to 90 percent of the span value.
5.3.2 Mid-Level Gas Cell or Filter.
One that produces an output equivalent
to 45 to 55 percent of the span value.
5.3.3 Zero Gas Cell or Filter. One
that produces an output equivalent to
zero. Alternatively, an analyser may
produce a zero value check by
mechanical means. such as a movable
mirror.
6. Performance Specification Test
Procedures
6.1 Pretest Preparation.
205
6.1.1 Calibration Gas Analyses. Cse
calibration gas prepared according \0
the protocol derIDed in Reference 10.2.
6.1.2 Calibration Gas Cell or Filter
Certification. Obtain from the
manufacturer a statement certifYing ~hat
the calibration gas cells or filters (zero.
mid-level. and high-level) will produce
the stated instrument response for the
continuous monitoring system. and a
description delineating the test
procedure and equipment used to
calibrate the cells or filters. At a
minimum. the manufacturer must have
calibrated the gas cells or filters agamst
a simulated source of known
concentration.
6.2 Continuous Monitoring System
Preparation.
6.2.1 Installation. Install the
continuous monitoring system according
to the measurement location procedures
outlined in Section 3 of this
specification. Prepare the system for
opera tion according to the
manufacturer's written instructions.
6.2.2 Conditioning Period. Follow the
procedure in Performance specification
2. Section 6.2.
6.3 Operational Test Period. Follow
the procedure in Performance
Specification 2. Section 6.3 and the
following subsections:
6.3.1 Calibration Error
Determination. Follow the procedures In
Performance Specification 2. Section
6.3.1.
6.3.2 Response Time Test Procedure.
Follow the procedures in Performance
Specification 2. Section 6.3.2.
6.3.3 Field Test for Zero Drift and
Calibration Drift. Follow the procedures
in Performance specification 2, Section
6.3.3.
6.4 System Relative Accuracy.
Follow the procedures in Performance
Specification 2. Section 6.4 and all the
accompanying subsections. The
reference method is Reference Method
10.
6.5 Data Summary for Relative
Accuracy Tests. Follow the procedures
in Performance Specifica tion 2, Section
6.5.
7. Equations. and Reporting
Follow the procedures in Performance
Specification 2. Section 7 and all the
accompanying subsections.
8. Reporting
Follow the procedures in Performance
Specification 2, Section 8.
9. Retest
Follow the procedures In Performance
Specific a tion 2. Section 9.
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IH46
Federal R~ster I Vol. 45, No. 35 I Wednesday. February 20, 1980 I Proposed Rules
10. Bibliography
10.1 Repp, Mark. Evaluation or
Continuous Monitors ror Carbon
Monoxide in Stationary Sources. U.S.
Environmental Protection Agency.
Research Triangle park. NC. Publication
No. EPA~/2-77~. March 1977.
10.2 Traceability Protocol for
Establishing True Concentrations or
Cases Used for Calibration and Audit.
of Continuous Source Emission Moniton
(Protocol No.1). June 15. 1978.
Environmental Monitoring and Support
Laboratory, Office or Research
Development. U.S. Environmental
Protection Agency. Research Triangle
Park. NC 27711.
10.3 Department of Commerce.
Experimental Statistics. Handbook 91.
Library of Congrell No. 63-60072. U.S.
Government Printing Office.
Washington. DC.
1f'R Ooc. -- V,lod %-.- us eml
IllUJIIQ COOl '--'-11
206
-------
Federal Register I VoL 45, No. 109 I Wednesday. June 4. 1980 I Notices
37729
(FRL 1507-4; EPA 5-A-80-8AI
Amended Permit Determination to
Indianapolis Power & Ught, Patriot,
Ind.
In the ma tter of the proceedings under
Title 1. Part C of the Clean Air Act (Act),
as amended, 42 U.S.C. 7401 et seq.. and
the Federal regulations promulgated
thereunder at 40 CFR 52.21 (43 FR 26388,
June 19, 1978) for Prevention of
Significant Deterioration of Air Quality
(PSD), relating to Indianapolis Power 8r
Light Company (lPl).
On March 29, 1977, IPlsubmitted an
application to. the United States
Environmental Protection Agency (U.S.
EPAI. Region V office. for an approval to
construct the Patriot (fonnerly Mexico
Bollom) Generating Station near Patriot,
Indiana. The application was submitted
pursuant to the regulations for PSD and
was considered complete as of October
3. 1977. In this application. IPL projected
its commencement of construction dates
as follows: Unit 1-ApriI1981. Unit 2-
April 1983 and Unit 3-ApriI1985.
U.S. EPA's subsequent denial of
permission to construct on August 7,
1978 was ultimately reviewed by the
United States Court of Appeals for the'
Seventh Circuit. The Court ordered U.S.
EPA to review new data received from
the Company and rule on the ability of
the pollution control equipment
proposed by the Company to meet the
applicable emission limitations. Such a
review was subsequently conducted by
U.S. EPA and a preliminary approval
was granted on August 23. 1979.
On September 20.1979. U.S. EPA
published notice of its preliminary
decision in the Vevay Reveille-
Enterprise and Kentucky Post. which
also stated that all materials on which
U.S. EPA has based its preliminary
approval were available for inspection
at the Switzerland County Library. This
included IPL's March 29. 1977
application. which. in turn. contained
the Company's projected construction
dates. A public hearing on U.S. EPA's
proposed action was held fm October
18. 1979 in Vevay, Indiana. Although
many comments were received by U.S.
EPA during the public comment period
and at the hearing. no issues were
raised with regard to (Pl's projected
dates.
On December 14. 1979. after review
and analysis of all materials submitted
by (PI.. the public record established at
the hearing and written comments. U.S.
EPA determined that the proposed new
construction in Switzerland County.
Indiana would be utilizing the best
available control technology and that
emissions from the proposed facility
would Dot violate applicable air quailty
increments of standards as required by
Section 165 of the Act. As one of the
conditions imposed on IPL in the pennit.
U.S. EPA stated that construction on the
three units would have to be
commenced as follows: Unit 1-by June
1981. Unit 2-by December 1982 and
Unit 3-by June 1984. On January 10.
1980. U.S. EPA's final determination was
published in the Federal Register. 45 FR
2095.
On March 4. 1980. IPl wrote a letter to
U.S. EPA, Region V. objecting to the
commencement of construction dates set
forth in the permit. In this letter, IPl
cited 40 CFR 52.21(s)(2) (June 19, 1978),
which provides as follows:
(2) Approval to construct shall become
invalid if construction is not commenced
within 18 months after receIpt of such
approval. if construction is discontlDued for a
period of 18 months or more. or If
construction is not completed within a
reasonable tune: The Administrator may
extend the 18.month period upon a
satisfactory showing that an extenSion IS
justified: This provision does not apply 10 the
time penod between construction of the
approved phases of a phased construction
prolect: each phase must commence
construction within 18 months of the
projected and approved commencement dale.
In light of this regulatory language. IPl
maintained that construction on the
three proposed units need not
commence unlll the following dates:
Unit 1-by October 1982. Unit 2-by
October 1984 and UOit 3-by October
1986. These dates are eighteen (18)
months from the projected dates in IPl's
original application.
As a result of 40 CFR 52.21[s)(2) (June
19.1978). U.S. EPA has determined that
the proposed umts need not commence
construction until the following dates:
Unit 1-by June 1981, Unit 2-by
October. 1984 and Unit 3-by October
1986. These dates thus incorporate the
18 month extensIOn period permitted by
the regulations. Other than this
provision and a miner change in the
reference to the recent judicial decision
of Alabama Power Co, v. Douglas M.
Castle. 13 ERC 1225 [D.C. Cir. 1979). no
other modifications in the December 14.
1979 permit have been made. This
207
includes U.S. EPA's reservation of its
right to require more stringent Best
Available Control Technology (BACT)
at a future date for all unconstructed
units at that date: if BACT has advanced
from the control strategy imposed by the
approvaL '
This approval to construct does not
relieve IPl of the responsibility to
comply with the control strategy and all
local, State and Federal regula lions
which are part of the applicable State
Implementation Plan, as well as all other
applicable Federal. State and local
requirements.
This deiennination may now be
considered final agency acllon which is
locally appealable under Secllon
307(b)(1) of the Act. A petlllOn for
review may therefore be filed in the U.S.
Court of Appeals of the Seventh Circuit
by any appropriate party in accordance
with Section 307(b)(1). Petillons for
review must be filed sixty (60) days from
the date of this notice.
For further infonnation. contact Eric
Cohen. Chief. Compliance Section.
Region V, U.s. EPA. 230 South Dearborn
Street. Chicago. Illinois 60604. (312) 353-
2111.
Dated: May 21. 1980.
Joho McGuire.
RegIOnal Administrator.
Region V.-Approval to Construct
[EPA-S-A-80-8AI
AuthorIty
In the Matter of Indianapolis Power &
light Company (IPl) Patnot. Indiana;
proceeding pursuant to the Clean Air
Act. as amended.
1. The approval to construct is issued
pursuant to the Clean Air Act. as
amended. 42 U.S.C. 7401 et seq.. (the
Act). and the Federal regulations
promulgated thereunder at 40 CFR 52.21
(43 F.R. 26388. June 19. 1978) for the
Prevenllon of Significant DeterIOratIOn
of Air Quality (PSD). This~is an
amendment of the original approval 10
construct the Patriot Generating St.1tlon
issued on December 14. 1979. (EPA-S-
A-8O-A).
Findings
2. The Indianapolis Power and Light
Company (IPl) proposes to construct the
Patriot (formerly Mexico Bottom)
Generating Station consisting of three
650 MW coal~fired boilers near Pa tnot.
in SWitzerland County. Indiana. The site
and impact area are designa ted Ca 5S II
pursuant to Section 162 of the Act.
SWitzerland County has been
designated attainment for all cntena
pollutants pursuant to SectIOn 107 of :he
Act (43 F.R. 8982. March 3. 1978)
-------
37730
Federal Register I Vol. 45. No. 109 I Wednesday, June 4, 1980 I Notices
3. [PI. submitted application
Informallon. which U.S. EPA deemed
complete on October 3. 1977. U.S. EPA
Issued preliminary approval on
February 3. 1978. and a public hearing
was held on April 20. 1978. Based on
Information presented at the hearing
and in pubhc comments. U.S. EPA
disapproved construction of tbe plant on
August 7. 1978. !PL appealed the denial.
On May 21. 1979. the U.S. Court of
Appeals for the Seventh Circuit
remanded the matter to the U.S. EPA for
decision of the air quality issue on the
basIs of the record established as of
August 7. 1978 and for further
proceedings on the matter of the
scrubber design.
4. On July 13, and July 30. 1979. !PL
supplemented its application with
scrubber design information. pursuant to
the court order.
5. On August 23. 1979, U.S. EPA
sranted prehminary approval of the
proposed construction.
6 A public notice soliciting comment.
on the pre liminary approval and offering
the opportunity for a hearing was
pubhshed by U.S. EPA on September 20.
1979. in the Kentucky Post and the
~'e1cy Reveille-Enterprise.
7. On October 18.1979. a hearing was
held in the Switzerland County Court
House for the purpose of gathering
public comments on the preliminary
approval of the Patriot Generating
Station by U.S. EPA.
8. The comment period established by
the nollces of September 20, 1979. was
open for receipt of written comment
until October 25. 1979.
9. IPL was gwen the opportunity to
respond 10 the public comment record
and submitted their response to U.S.
EPA on November 13. 1979.
10. The boilers at the Patriot
Genera ting Sta lion are subiect to the
requirements of 40 CFR Part 60. Subpart
Da. Standards of Performance for
Electric Utility Steam Generating Units
14-1 FR. 33580. June 11. 1979).
11. After review and analysis of the
matenals on air quality in the record as
of August 7. 1978. the scrubber desIgn
information submitted bv IPL the
comments submitted in ~ntlng and at
the r'lblic heanng and [PL's response to
the: 'blic comment record. U.S. EPA
find 1at best available control
tech, 'ogy will be employed at the
Patr,) Generating Station and the PSD
incr~ments and the National Ambient
Air Quality Standards will not be
violated.
ConditIOns
12 Parllcula te emissions from the
boiler exhaust gases shall not exceed
0.03 Ib./million BTU heat input.
13. Boiler exhaust gases shall not
exhibit an opacity grea ter than 20
percent (6-minute average) except fLr
one 6-minute period per hour of not
more than 27 percent.
14. Nitrogen oxide emission. from the
boiler exhaust gases shall not exceed 0.6
Ib./million BTU beat input.
Conditions 12 through 14 represent
applications of the best available
control technology (BACT) as required
by Section 165 of the Act.
15. Sulfur dioxide emiuions from the
boiler exbaust gases shall not exceed
0.55 Ib./million BTU heat input.
16. The sulfur dioxide scrubber system
shall be maintained at a minimum
removal efficiency of 91 percent.
Conditions 15 through 16 are
necessary to ensure that the Cla1lS II
increments for sulfur dioxide are not
exceeded. These conditions also satisfy
the requirements for application of
BACT to sulfur dioxide emissions.
17. Continuous emiuions monitoring
systems shall be installed. calibrated.
operated and maintained in accordance
with 40 CFR 6O.47a for the following:
(a) opacity
(b) sulfur dioxide (inlet and exit)
(c) nitrogen oxides
(d) oxygen or carbon dioxide
The monitoring data and heat Input
for the reporting period shall be
submitted to the Chief, Compliance
Section. U.S. EPA in accordance with
the provisions of 40 CFR 60.7.
18. A continuous ambient air
monitoring network sball be installed.
calibrated. operated. and maintained for
the measurement of:
(a) wind speed
(b) wind direction
(c) ambient air temperatUl'l!
(d) total suspended particulate
(e) sulfur dioxide
The monitoring shall be designed and
sited in accordance with U.S. EPA
monitoring guidelines and with the final
design and operating procedures subject
to review and approval by U.S. EPA.
Tbis monitoring sball begin at least
one year prior to the start-up of the first
generating unit and shall continue for
the life of the station or until U.S. EPA
informs !PL that it may cease. The data
shall be reported quarterly to the Chief.
Compliance Section. U.S. EPA. The data
to be reported is specified in AEROS
Users Manual (EPA-450/2-76-029.
OAQPS No. 1.2-039) and is to be coded
onto the SAROAD Air Quality Data
forms or on magnetic tape in SAROAD
format.
208
19. IPL shall submit to U.S. EPA 30
days prior to mitial start-up of the first
boiler. a copy of detailed operation.
maintenance and staff training
procedures for air pollution control
equipment. .
20. No air pollution control equipment
design parameters. boiler operating
parameters. physical and dynamic stack
parameters. or building parameters may
be changed without prior written
authorization of U.S. EPA. However.
U.S. EPA reserves the right to require
more stringent BACT at a future date for
all unconstructed uni1s at that date, if
BACT has been advanced from the
control stategy imposed by this
approval.
Conditions 17 through 20 are
necessary to ensure that on a continual
and permanent basis. emissions from
the Patriot 'Generating Station do not
violate the Class U increments for
particulate and sulfur dioxide and the
emissions standards established in
conditions 12 through 15.
21. To ensure that best available
control technology is being implemented
to minimize fugitive particula te
emissions: .
(a) Particulate emissions from coal
unloading shall not exceed 10 percent
opacity for the duration of the unloading
operation.
(b) All coal conveyors except the belt
conveyor along the stacker reclaimer
track shall be completely enclosed.
(c) All transfer points shall be
completely enclosed. This does not
include transfer from the stack reclaimer
to the stack out pile. barge unIoader.
Bnd the belts along the stacker reclaimer
track.
(d) Emissions from all transfer houses.
surse bins. and storage silos shall be
controlled by dust collectors.
(e) The coal piles shall be sprayed
with a surfactant on a regular basis as
needed to minimize fugitive dust.
(f) The bottom ash will be sluiced.
dewatered, and sent to a solid waste
processing area.
(g) The dry ash from the electrostatic
precipitators will be pneumatically
conveyed to a pair of fly ash storage
silos with dust collectors. From the silos,
the fly ash will be conveyed to the solid
waste processing area.
Approval
22. Approval to construct the Patriot
Generating Station is hereby granted to
the Indianapolis Power and Light
-------
Federal Register I Vol. 45. No. 109 I Wednesday, June 4. 1980 I Notices
37731
Company subject to the conditions
expressed herein and consistent with
the materials and data filed by the
Company. Any departure from the
conditions of this approval or the terms
expressed in the data filed by the
Company. must receive the prior written
authorization of U.S. EPA.
23. The United States Court of
Appeals for the D.C. Circuit has issued a
ruling in the case of Alabama Power Co.
vs. Douglas M. Costle (7~1006 and
consolidated cases) which has
significant impact on the U.S. EPA
prevention of significant deterioration
(PSD) program and approvals issued
thereunder.
It is possible that the decision will
require modification of the PSD
regulations and couJd affect approvals
issued under the existing program..
Examples of potential impact areas
include the scope of best available
control technology (BACT). source
applicability. the amount of increment
available (baseline definition). and the
exJent of preconstruction monitoring
that a source may be required to
peliorm. The applicant is hereby
advised that this approval may be
subject to reevaluation as a resuJt of the
court decision.
24. This approval is effective
immediately. This approval to construct
shall become invalid if construction of
Unit #1. is not commenced by June 14.
1981. The following construction
guidelines shall be considered the
projected and approved construction
commencements dates pursuant to 40
CFR 52.21(s)(2). Construction of Unit #2
must commence with 18 months of April
1.1983. Construction of Unit #3 must
commence with 18 months of April 1.
1985. The Administrator may extend the
209
time period for the construction of Unit
#1 only upon a satisfactory showing
, that an extension is justified.
Notification shall be made to U.S. EPA
.of the commencement of construction of
each unit 5 days after construction is
commenced.
25. This approval does not relieve IPL
of the responsibility to comply with the
control strategy and all local. State and
Federal regulations which are part of the
applicable Implementation Plan. as well
as all other applicable Federal. State
and local requirements.
26. A copy of this approval has been
forwarded to the Switzerland County
Public Library. Ferry Street. Vevay.
Indiana. .
Dated: Apn115. 1980.
John McGuire.
RegIonal AdminIstrator.
IFR Doc. BO-t8lm FIled ~ IUS ami
INWNQ CODE &M004I-t11
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Federal Regisler f Vol. 45. No 116 f Frida\'. June 13. 1980 f Proposed Rules
40169
40 CFR Part 52
I FRL 1514-81
Approval and Promulgallon 0'
Implementation Plans; Utah SO.
Control Stralegy
AGENCY: Environmental Protection
Agency.
ACTION: Proposed rule.
SUMMARY: Thl8 notice proposes to
reInstate the EPA sulfur dioxide (SO.)
emIssion limitation (6030 pounds per
hour) and proposes to amend the
fug:tlve emissions reQuirement8.
comphance 8chedules and emiSSlon8
testiDg requirements applicable to the
Kennecott Copper Corporation smelter
in L.tah The proposed achon would
establish 8 final compliance date not
later than December 31.1982. and
provide the smelter the opportunity to
demonstrate its eligibility for a primary
no~lerrou8 smelter order.
DATE: Written comments on the
proposed action 8hould be 8ubmilled on
or before July 14. 1980.
ADDRESSES: Submit written comments.
preferably in triplicate. to: Office of
Regional Counsel. Environmental
Protection Agency. Region VIII. Suite
900.1860 Lincoln SlreeL Denver,
Colorado 80295.
Availabilitv of 8upporhng informatJon
A docket (No". 8A-7~1J containing
consldNabl~ greater thdn the 24-hour
pnmary natlondl stdndim] of 365 fJ-g/m'
Wf~e esllmated. However. as iDdicated
in the \echnlCal support document EPA's
cu~rl'l1l SO. emiSSion hmltahon of 6030
Pl enJs pfr hour. which WdS based on
dl~fuslOn modeliDg for the smelter prior
to its modlflcahon. IS necessary to attam
"d maintain the 24-hour standard.
Slnf e the 12oo-foot stack installed by
~l'~necott to replace the two 4OO-foot
".leks pre\' iously used at the smelter
dr>t'S not result In an increase 10
allowable emissions for the area of
md.\lmum predicted ambient impact at
L<,ke Pomt. EPA has d(.termined that the
np\\, stdck does not permit the use of
d"perslOn enhdncement in place of
C0nt.iDt emiSSion controls. Therefore.
Ef' \ is not undertdkmg a formal
e' !uatlOn to determine if the new stack
represents Good Engineering Practices
under Section 123 of the Act.
Consequently. EPA is withdrawing the
3700 pounds per hour SO. emission
limitation proposal of 1978 and
proposing to reinsta te the emission
limitation promulgated in 1975. In
addition. EPA is proposing 10 amend the
fugItive SO. emissions requirements for
f,est engineering techniques to insure
that all of the fugitive capture equipmenl
currently installed at the smelter is
operated and maintained properly. The
proposed regula tion describes these
en;meering techniques [primary and
secondar\" hoods. vents. fans. duclwork,
etc ) and ~equires Kennecotl to submit to
EI'A a plan for their operation and
malntpnance.
EPA's fl:ovember 26.1975. SO.
Tf'gulations set July 31. 1977. as the time
for achievement of fmal compliance.
Before July 31. 1977. however. EPA
sllpulated in connection with pending
litlgdtlOn that it intended 10 promulgate
adJltlonal SO, reguldllons which might
allow the use of a Supplementary
Control System (SCSJ and that.
th(.rdore. it would not enforce the
eXisting SO, regula lions during the
mftonm.
As noted abo\'e. The Clean Air Act
amendm..nts of 1977 required SIP
..mIssion limitatIons 10 be achieved
through the use of constant controls. but
"ould permIt a smelter which obtained
an 1\;50 under Section 119 to use SCS on
an In"'nm basIs bpfore achieving final
cumpllance with its SO, emission
limitations.
1n light of these Hents. EPA has not
enforcl'd the /lioHmber 26. 1975. SO.
rpguldtlOns. Smce EPA has in effect
tolled the compliance requirement
before the da te by which compliance
"dS required In anticipallon of the
posSIble use of SCS. the agency believes
that it is consistent with the intent of
Congress In enacllng Section 119 to
amend the compliance date by the
amount of time necessary after the
promulgallon of regula lions under
Section 119 to installihe required
control equipment. Accordingly. today's
proposal would require Kennecotllo
meet its emission limitation as
expedillously as possible after the
effective date of the NSO regulations.
210
Since that date is imminenl, EPA
believes it can now propose an outside
date for final comr.liance. and that such
date should be nc later than December
31.1982. EPA chC'se the date December
31. 1982. becaus" it believes that the
expeditious install.ilion and operation of
the expected cc:'trol equipmenl
necessary 10 meet Ihe emission limil
proposed loday can be accomplished by
Ihal date.
Finally. EPA is proposing 10 clarify the
emission testing requirements
applicable to the smelter. The proposed
amendmenls. which are necessary 10
avoid potential misinterpretation of the
current provisions. specify more clearly
the continuous emission moniloring and
stack testing criteria for detennining
compliance with the emission limitation.
as well as the applicability of the Iwo
methods. Because of prior
misunderstanding. the revised
provisions include a specification for the
nonnal smelter operating rate dUTIng
manual testing. Recent EPA policies 10
apply more adequate quality assurance
specifications for the emission
monitoring equipment have also been
included.
The technical support document
containing the revised diffusion
modeling and the basis for withdrawal
of the proposed 3700 pound pPr hour
emission limitation is included in the
rulemaking docket.
Interested persons may participate in
this rulemaking by submitting wrillen
comments. preferably in triplicate. to the
Office of Regional Counsel.
Environmental Protection Agency.
Region VIII. Suite 900. 1860 Lincoln
Street. Denver. Colorado 80295. Public
comments received by July 14. 1980 will
be considered in developing the final
rule. All comments will be available in
the docket for public inspection.
EPA is also providing the opportunity
for interested citizens to request a public
hearing Requests for a public hearing
must be in writing and directed to U.S-
EPA. Region VIII. OffIce of Regional
Counsel. 1860 Lir,coln Street. Denver,
Colorado 80295. If there is sufficient
interest. a public hearing will be
scheduled. Requests for a hearing musl
be received by July 14. 1980.
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Federal Register I Vol. 45. No. 116 I Friday. June 13. 1980 I Proposed Rules
40171
Subpart TT -Utah
Section 52.2325, paragraphs (c) and (d)
are revised to read as follows:
152.2325 Control .tratevY: Sulfur oxide..
(c) Regulation for control of fugiti\'e
Bulfuroxides emissions (Wasatch Front
Intrastate Region). (1) The owner or
opera tor of the Kennecott Copper
Corporation smelter located in Salt Lake
County. Utah. in the Wasatch Front
Intrastate Region shall utilize best
engineering techniques for reducing
escape of pollutants to the atomosphere
and to capture sulfur oxides emissions
and vent them through 8 stack or stacks.
Such techniques shall include. but not
be limited to:
(i) Installing and operating primary
hoods and slag and matte tapping port
hoods on each active reactor;
(ii) Installing and operating primary
and secondary hoods on each active
convertor;
(iii) Installing and operating vents.
fans. and ductwork in the ceiling above
ach reactor and convertor aisle to
capture emissions in the general
building air;
[iv) Maintainmg and uperating to
deisRn specifications. and in continuous
and full use when the respective procpss
unit[s) is (are) in operation. all
mechanical parts. including but not
limited to hoods. doors. dampers. fans,
and their controls:
(v) Maintaining all ducts. flues. and
stacks in a leakfree condition;
(vi) Maintaining all reactors and
converters under normal operating
conditions in such a fashion that out
leakage of galies to the air will be
Pl'ev'ented to the maximum extent
possible;
(vii) Wherever possible. ducting
emissions through the tallest stack or
stacks serving the facili ty;
(viii) Wherever possible. passing the
ernuent from all hooding and ceiling
vents through the tallest stack or stacks
serving the facility; and
(ix) Mmimizing exhaust of pollutants
d:rectIy from any building opening.
I=J The owner or opera tor of the
Kp:mecott Copper Corporation smelter
shall, within sixty [50} days of the date
of promulgation of this regulation.
submit to the Director. Enforcement
Di\ ision. Environmental Protection
Agency (EPA). Region VIII. a plan for
achieving and maintaining the best
englOeering techniques required in
paragraph (cJ(l) of thIs secllon. Such
plan shall include as a minimum:
[i) Operation and malOtenance
specifications for the techniques listed
in paragraph (c)[l) and for any building
e\'dcuation system not vented to a stack;
(II) Analysis of best engineering
tpchniques for captunng sulfur exides
emissions at the feed end of each
reactor;
(iii) Detailprj plans and compliance
schpdules to achieve the best
englOeering techniques.
(3) Within ninety (90) days of receipt
of the plan required in paragraph (c)[2]
of this section, EPA, Region VIII. will
e\'aluate it for effectiveness in reducing
SO, emiSSIons;
(i) If EPA finds that the plan is
adequate, the approved plan. its
requlrempnts. and dny compliance
schedules therein, shall become a part of
this regulation by incorporation;
(il) If the plan is determmed to be
inadequate. EPA will provide notice to .
the smelter owner or opera tor and will
promulgate a substitute plan within 120
day s of such notice. Any stich
promulgated plan will be incorporated
as a requirement of this regulation.
(4) Actions implemented by the
smelter owner or operator under the
plan developed under section (c)(2) (or
promulgated under Section (c)[3)) of this
section shall be reportpd monthly to the
Director, Enforcement Division, EPA.
Region VIII. Such report shall include,
but not be limited to, the date and
number of hours any of the fugitive
collection and control devices were not
operational and any actions taken to
correct such problems and~void their
recurrence.
(d) Regulation for control of sulfur
0.\ ides emissions n1/asateh Front
Intrastate Region). (1) The owner or
operator of the Kennecott Copper
Corporation smeller located in Salt Lake
County, Utah, in the Wasatch Front
Intrastate Region shall not discharge or
cause the dischjlrge of sulfur dioxide
into the atmosphere in excess of 6030
pounds per hour (2735 kg/hr), maximum
six-hour average as detennined by
eilher of the methods specified in sub-
paragraph (4) of this paragraph. Such
limitation shall apply to the main
smelter stack which vents sulfur dioxide
emissions Irom the smelter premises. but
not including fugitive emissions not
capable or capture by best engIneering
techniques. Sulfur trioxide and sulfuric
211
aCid l'tJi&t are not to be counted a~dlnst
the sulfur dioxide emission limitatIOn,
(2)[i) The owner or operator of the
smelter subject to this paragraph shall,
no later than thirty (30) days folloWIng
the effective date of this paragraph.
submit to the Administrator for approval
a proposed ccmpliance schedule thdt
demonstrates compliance with
paragraph (d)[l) of this section as
expeditIOusly as practicable, but not
later than December 31, 1982.
[il) Tbe compbdnce schedule
submitted 1o Ihe Administrator pursu,mt
In paragraph (dH2)[1) of this section
shall provide for increments of progress
toward compliance. The dates for
achievement of such increments of
progress shall be specified. Incn,ments
of progress and dates for achlevpment
shall include. but not be limited to. the
following:
(a) No later than two (2) months
following the effective date of this
paragraph-Submit a final control plan
to the Administrator for meetIng the
requirements of paragraph (d)[l) of this
section:
(b) No later than four (4) mon.ths
following the effective date of this
paragraph-Let necessary contracts or
issue purchase orders for process and/
or control equipment to be used to
accomplish the required emissIOn
con trol;
(e] No later than six (6) months
following the effective date of this
paragraph-Initiate on-site construction
or installation of emission control
equipment and/or process modification;
(d) No later than November 30,1982-
Complete on-site construction or
installation of emissIOn control
equipment and/or proces modificdtion;
(e) No later than December 31,1982-
Achieve and demonstrate full
compliance with the requirements of
paragraph (d)[l) of this section.
{iii) The owner or operator of the
smelter subject to the requirements of
this paragraph shall certify to the
Administrator within five (5) days after
the deadline for each increment of
progress. whether or not the required
increment of prQgfess has been met.
(iv) Notice must be given to the
Administrator at least sixty (60) days
prior to conducting a perfonnance lest to
afford him the opportunity to have
observers present.
(v) A written report of the results of
such performance evaluation testis)
shall be flIfTlished to the Administrator
within 30 days of the commencement of
sucb testIs).
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Federal Register I Vo\. 45. No. 116 I Friday. June 13. 1980 I Proposed Rules
40172
(\" If the smelter subject to this
pi,' !\:o such
wmpliance schedule ma~ provIde for
flndl. ,n:pll..lnce after Der!'mber 31.
198~ If approved h\ the Admlnlstrdtor.
h,:'.h ".h1':uule shall rl'pl..ce the
wrrpJ1ance schedule set forth In
pards.:rdph (dH~1I1I1 of thiS sectIOn.
(\1,,) Any comr,linnce s, h,.uule
slJl'~1It,,'d to thp Administrator pursu.,nt
In p..""...ph (d)l~II\1I1 of this sectIon
sh.dl pro\ Ide for Increments of prngrt.,s
to",..rd compliance, The ddtl'S for
01 Llt'Hmpnt of such Increments of
prugress shdll bl' speClf,,'d tncrvmenb
of pro~ress shdlllndudf'. but not be
IImlt,'J to. the Increment specified In
p" 'Igr..ph lull2)111) of thiS secllon.
(Iii" Th!' ownf'T or operdtor of any
sme!I,'r to which thl> pdrdgraph IS
Oppllcd!..le shallln,tdl!. c.dlbrate.
O101ll1l.lIn. and op,'rnte a mp.lsuremf'nt
S} ,I,'ml <) for conllnuousl} mOnltorin)o1
sulfur dioxide emissions and stack gas
\l)lu~letnc now rates 10 the maIO
s:11el:"r star k and in the outlet of each
sulfur dlo>.,ue control (acIllly For the
purpose of thiS paragraph. "conhnuous
emission mOnltonng" means the laking
and fl'COrt1lng of at least one
n1CU,urem!'nt of sulfur dioxIde
conrenlI.lllon and !!as now rate from tbe
aff('( ted stack and Ihe outlet of each
sulfur d,o"de conLTol facility in each 15-
011nl1"> pt.nod.
!1. .\ Ithln ninP (9) months after the
err,.. e d.lle of this paragraph. and at
such her times in the future as tbe
Adrr.'. ,trator may spewy. the sulfur
d",,,d, concentration measurement
5\ sli'm[,) installed and used pursuant 10
this p.iTagraph shall be demonslIall'd to
n.eel the measurement S\ stem
pl'rformance speclflcall';ns prescribed in
Appl'ndi~ D to th,s Part. as amended. or
0' a,,'!'ndpd In subparagr~ph (4) below,
Th,' S} ,fI'm ~halJ he evaludlpd in units
of thp stdndard, Accurncy should be
1'\ aluated by conducting at least 3 two-
hour manual type referencl' method
tests for SO. and velocity during each of
three sequential 9-hour test periods and
:a!culated as prescnbl'd in Appendices
D and E. as amended. of this part.
(III) \\'lIhln nine (9) months after the
effective date of this para!!raph, and at
such othpr times 10 the future as Ihe
Administrator may specify. the stack
!!dS volumetric now rate measurement
svstem(s) Installed and used pursuant to
tf\ls paragraph shall be demonslrated to
me'pt the mf'asurement system
pcrformancl' specif1cations prescribed in
Appendi~ E to this Pdrt. as amended. or
itS amended in su!..parRgraph [4) below.
(1\) On.site analysis. results
calculation. and preliminary results of
SO. emISSion tests during all monitor
cl'rllfication and emission performance
k
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Federal Register I Vo\. 45. No. 116 I Friday. June 13. 1980 I Proposed Rules
40173
any monitor during the month. includmg
any time which the monitor was
remo\'ed or otherwise inoperable for
any reason.
(d) The date and results summary of
each e\'aluation of any portion of the
monitoring system during the month.
(e) The percent (%) of on-line
availability time by week for each
continuous emission monitoring modular
part (component) as well as a
description of component down time.
(f) All conversion values used to
derive the 6-hour emission for SO,
which include. but are not limited to:
temperature. velocity of stack gases.
moisture. parts per million (ppm). and
production levels.
(xi) Each monitor modular part (i.e.
50,. volumetric flow rate. and data
recording and handling units) of a
continuous emission monitoring system
shall attain a minimal annual (the four
quarters of a calendar year) on-line
availability time of 85 percent. If the
entire system fails to operate with this
reliability. the operator must. with the
first monthly report of the next year.
explain in detail the reason(s) for this
lack of performance.
(xii) The continuous emission
monitoring and recordkeeping
requirements of this paragraph shall
become applicable nine (9) months after
the errective date of this paragraph.
(4J(i) Compliance with the
requirements of paragraph (d)(1) of this
section shall be determined on a
continuous basis using the emission
measurement system(s) installed.
calibrated. maintained. and operated in
the main smelter stack in accordance
with the requirements of paragraph
(dJ(3) of this section. For that stack
equipped with the mesurement system
required by paragraph (d)(3] of this
section. a running 6-hour average sulfur
dioxide emission rate shall be
calculated as of the end of each clock
hour. for the preceding six hours. in the
following manner.
(a) Divide each 6-hour period into
twenty-four 15 minutes segments.
(b) Determine the emission rate on a
compatible basis from a sulfur dioxide
concentration and stack gas flow rate
measurement for each 15-minute period
for the main smelter stack. These
measurements may be obtained either
by continuous integration of sulfur
dioxide concentration and stack gas
now rate measurements (from the
affected stack) recorded during the 15-
minute period or from the arithmetic
average of any number of sulfur dioxide
concentration and stack gas flow
readings equally spaced over the 15-
minute period. In the latter case. the
lame number of concentration readings
shall be taken in each 15-minute period
and the readings shall be similarly
spaced within each 15-minute period.
The sulfur dioxide emission rate for
each of the twenty-four segments for
that stack shall be determined by
multiplying the stac\.. gas volumetric
flow rate (m'/hr at standard conditions,
dry basis) by the sulfur dioxide
concentration (kg/m' at standard
conditions. dry basis).
(c) Calculate the arithmetic average of
the 24 emission rates calculated for each
6-hour period for the stade Calculations
will be reported in kg So../hr.
(ii) Notwithstanding the requirements
of paragraph (d)'4)(i) of this section.
compliance with the requirements of
paragraph (dJ(l) of this section may be
determined for a specific period of time
(i.e. only that time of the manual test) by
using the methods described below at
such times as may be specified by the
Administrator. Any manual stack test
conducted under this paragraph may be
used both to evaluate current emission
levels and to reevaluate the
perfonnance of the continuous emission
monitor system(s) at that time. For the
main smelter stack equipped with the
measurement system(s) required by
paragraph (d)(3) of this section. a 6-hour
average sulfur dioxide emission rate (kg
SO,/hr) for a specific period of time,
andlor when evaluating the accuracy of
the continuous emission measurement
system. shall be deterrruned as follows:
(a) During testing of the stack
emission rate the process shall bum
fuels. use raw materials. feed air and
oxygen. and maintain process
conditions representative of maximum
operating conditions. while fugitive
emission capture systems are in
compliance with the requirements of
para~raph Ie) and under such other
conditions as the Administrator may
specify. Given the processing units
existing in February 1980 (three reactors.
four convertors, etc.). those operating
rates shall include. but not be limited to.
at least the following: two reactors. at
least two convertors. the molybdic oxide
roaster. the boilers. and the super
heaters. all in full operation, resulting in
production of approximately 38 tons per
hour of blister copper. Testing shall
continue during those times when
reactors and convertors are rolled out
for normal tapping and charging, but
shall be temporarily suspended during
process upsets which result from
abnormal occurrences. (If in the future
the number of processing units or an
operating parameter{s) should change.
the operating rates specified above. or
as may be otherwise specified by the
Administrator. may be modified by
EPA.) Testing shall not proceed during
any time when emissions from any
process unit are vented to another stack
or emission points.
213
(b) Concentrations of sulfur dioxide in
stack gases shall be determmed by using
Method II as described in Part 60 of thIS
chapter. The analytical and
computational portiOTls of Method II as
they relate to determination of sulfuric
acid mist and sulfur trioxide as well as
isokinetic sampling may be omitted [rom
the overall test procedure.
(e) Three independent sets of
measurements of sulfur dioxide
concentrahons and lItadc gas volumetric
f1aw rates shall be conducted during
three 9-hour periods for the stack.
During each 9-hour period three
nonconcurrent tests, each of at least two
hours of sampling time. concurrent with
acceptable process operatIOn. shall be
conducted. All tests must be complell'd
within a 72-hour period.
(d) In using Method 8, traversing shall.
whenever possible, be conducted
according to Method 1 as described in
Part 60 of this chapter. or as othen\ise
prescribed b}' the Adrrunistra tor. The
minimum sampling volume for eilch 2-
hour test shall be 1.133 m' [40 ft-,
corrected to standard conditions. dry
basis.
(e) The volumetric flow rate of the
total effluent £rom the stack evaluat£'d
shall be determined by using Method 2
as described m Part 60 of this chilpler
and. whenever possible, by tra.ersmg
according to Method 1. or as otherv.'ise
prescribed by the Administrator. CdS
analysis shall be performed by using the
integrated sample technique of Ml'thod 3
as described III Part 60 of thi.! chapler.
Moisture content shall be determined by
use of Method 4 as described in Part 60.
Appendix A. of this chapter.
(fJ The gas sample shall be extracted
at a rate proportional to the gas velocity
at the sampling point
(g) For each 2-hour test period. the
sulfur dioxide emission rate for the
stack shall be determined by mull1plying
the stack gas volumetric flow rate [m'l
hr at standard conditions, dry basis) by
the suUur dioxide concentration ("g/m'
at standard conditions. dry basi~J The
emission rate in kg/hr maximum 6-hour
average for the stack shall be
determined by calculating the arithmf'tic
average of the results of the thr£'e ~.hour
tests conducted within a 9-hour perIOd.
(hI The averagp emission rate from
the three independent sets of
measurements ill kg/br maximum 6-hour
average for the stack is delermlnl'd by
calculating the arithmetic average of the
6-hour average values calculated
pursuant to paragraph [d)(4J[ii)(g) of th'"
sectIOn.
IFR[J,~ ~1:'6IW.,i,Jf~lZ....80 84~"J1,!
BilliNG CODE '~I-t1
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Federal Register / Vol. 45. No. 120 / Thursday, June 19, 1980 / Rules and Regulations
41415
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 55
(FRl1507-71
Energy Related Authority; Delayed
Compliance Order for the Virginia
Electric and Power Company'.
Portsmouth Generating Station
AGENCY: Environmental Protection
Ag,'ncy.
ACTION: Final rule.
._--~
SUMMARY: This notice announces that
the Environmental Protection Agency
(EPA] IS Issumg an aummistrallve order
to the Vlrglfiia Electric and Power
Cumpany's Portsmouth Generatmg
SIJlion rpquiring its Boilpr Number 4 at
Por"moulh. Virginia to achiev'e
con I'l'dnce by June 30. 1982 with air
p"ll.llion rpquirements under the
\'Ir~.nid Sidle Implempnldlion Pldn.
EFFECTIVE DATE: June 19. 1980.
FOR FURTHER INFORMATION CONTACT:
~!r ~1.Hk E. Gnrrlson. U S.
L:n\ Ironmpntal Protection Agency.
Rf'~!on 111. S,xth dnd Walnut Streets.
1'IIIIrltlt,Iphld, PennS}lVanld 19106 (21~
54--~~.j.;J.
SUPPLEMENTAL INFORMATION: EPA ha~
dPH!"p..d an administralive order
which IS being issued under Section
11 3Id)(5) of the Clean Air Act (the Act].
42 l' S C. 7491 et. s~q.. to the Vlrgmid
F',.. 'nc and Power Company's
Port,mouth Generdtmg Station requITing
its Boiler !'\umbe~ 4 at Portsmouth.
V"~l11la to achieve compliance "ith
\',rglnla State Air Pollution Control
B",,,,I. Section IV. RLlIes 2 and 3 of the
\'I'~'nla State Imp!ementation Plan by
Jun.. 30. 19112 This order requires thaI
1111' V"glnla EIt'ctTlc and Power
C"r p"ny's Portsmouth Gcncrdllfig
Sldtlon Install control equipment on
Buil,'r :\umber 4 according to the
schedule set forth below. prescribes
inlenm emission reduction
reqclrements. specifies emission
j"T. . "lions, coal pollLltant
choHacteTistics. and requires monitoring
and reporting of air qualitv and air
pollutant emIssions data. Compliance
with the terms of the order precludes
any further enforcement by EPA under
Secllon 113 of the Act and any citizens
suits under Section 304 of the Act
against the SOLlrce for violations of the
Virginia State Implementation Plan
provisions covered by the order.
The entire contents of the order were
proposed in the Federal Register on
October 2. 1979 (44 FR 56721). In this
notice EPA invited the PLlblic to submit
written comments and requests for a
public hearing as to whether EPA shoLlld
issue the order. During the 30-day public
comment period ending November 1.
1979 no comments were received by
EPA.
As indicated in the proposed notice of
October 2. 1979, regulations promulgated
in 40 CFR part 55 under the authority of
Section 119 of the Act. as in effect prior
to the amendments of August 1977, are
being revised to renect this statutory
change. Any extensions to be granted
under the new authoTlty of 113(d)(5) will
be promulgated in part 55. Because of
thp shorter time period necessary for
promulgation of a delayed compliance
order (DCO) as compared to the time
npcpssary for revision of the regulations
under 40 eFR part 55, Ihis order for the
Virginia Elpctrlc and Power Company is
promulgated under part 55 prior to the
publication of the revised regulations.
One major change that the Clean 1\ir
Act Amendments of 1977 have had on
Implementation of the Energy Supply
and Env'ironmpntal Coordination Act is
that written concurrence of the
Governor of the appropriate State must
bp obtained on any date EPA proposes
to certify to the Department of Energy as
the earliest date a prohibited source can
convert to coal in compliance with
applicable air pollution requirements.
Th,s concurrence was rpquested of the
Honorable John N. Dalton. Governor of
the Commonwealth of Virginia, and was
received on /l;o\.ember 21. 1979.
Therefore, based upon the requpst by
the Virginia Electrac and Power
Company. the EPA's findings, and the
written concurrence from Governor John
N Dalton. this order is hereby issued In
addItion. thiS order is being made
214
effective immediately since no purpose
would be served by delaying its
effective date.
(42 V.S.C. 7413(d))
pated: June 9.1980.
Douglss M. CosUe.
AdmInistrator.
Part 55 of Chapter I, Title 40 of the
Code of Federal RejJulations is amended
by adding a new t 55.972 as follows:
Subpart VV-Vlrglnia
f 55.972 Delayed Compliance Order.
The Administrator hereby issues a
delayed compliance order to the
Virginia Electric and Power Company's
Portsmoulh Generating Station. Boiler
NLlmber 4. PortsmoLlth. Virginia (the
source). upon the following conditions:
(a) Primary standard conditions. The
source shall not burn coal which resLllts
in the emissions of particulate matter in
excess of 2263 pounds of particuldte
matter per hour from Boiler Number 4 al
maximum load and 492 pounds of
particulate matter per hour at maximum
load from Boiler Numbers 1, 2 and 3
combined. in accordance with the
following schedule of compliance:
(11 During the period of the ORDER's
effectiveness, the source shall not burn
coal with an ash content exceeding 12
percent (12%) and a high heating value
of less than 12.000 British Thermal Units
(BTU's) per pound.
(2) Within 30 days of receipt of this
ORDER. the Virginia Electic and Power
Company (the Company) shall submit a
proposal for a complete air quality
monitoring network to be set up by the
Company in the vicinity of the SOLlrce as
required by subparagraph (VI)(A)(1).
(3) Within 90 days after receiving EPA
approval of the proposed network. the
Company shall complete installation
and begin operation of the air quality
monitoring network.
(4) Within 90 days of receipt of this
ORDER, the Company shall submit for
EPA approval the methods. procedures
and devices the Company intends 10 use
to obtain the information required by
subparagraph (VI)(B).
(b) Plan for compliance with SectIon
IV, Rules 2 and 3. The source shdll
comply with Section IV. Rule 2 (effective
date: March 17, 1972) and Rule 3
(effective date: March 17, 1972; amended
August 11. 1972) of the Commonwealth
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41416
Federal Register / Vol. 45. No. 120 / Thursday. June 19. 1980 / Rules and Regu)ations
of Virginia in accordance with the
following increments of compliance.
(1) April 1. 19~Enter into contracts
for particulate emissions controls and
other equipment necessary for final
compliance.
(2) May 1. 19~5ubmit for approval
to the Director of the EPA .Region III Air.
Toxics and Hazardous Materials
Division (hereinafter referred to I!s the
Director). contracts for continuous
particulate emission reduction systems
and other equipment necessary for final
compliance.
(3) April 1, 1981-lnitiate on-site
construction or installation of
continuous particulate control systems.
(4) April 1. 1982~omplete on-site
construction or installation of
continuous particulate control systems.
(5) June 30. 1982-Perform emission
tests in accordance with 40 CFR Part 60
and submit reports demonstrating final
compliance with the Regulations of the
Commonwealth of Virginia, Section IV.
Rules 2 and 3.
(c) Interim requirements. The source
shall comply with the following interim
requirements prior to achieving
compliance with Section IV, Rules 2 and
3 of the Commonwealth of Virginia.
(1) Within 60 days of commencing the
use of coal in Boiler Number 4. the
Company shall perform source testing
for particulate emissions using EPA
Method 5 as specified in Appendix A of
Part 50, Title 40 of the Code of Federal
Regulations, as amended. The Company
shall perform such tests in a manner
prescribed by EPA Region 111 and shall
provide the Regional Energy
Coordinator a minimum of 15 days
written notice prior to conducting such
tests. The Company shall provide a
complete report containing all
information pertinent to the
performance and results of the stack
tests within 30 days of completing such
tests.
(2) Within 60 days of installation of
the continuous opacity monitor required
under subparagraph (VI)(A)(6). the
Company shall conduct a Performance
Specification Test (PST) in accordance
with Performance Specification 1,
Appendix B of Part 60. Title 40 of the
Code of Federal Regulations. The
Company shall notify the Regional
Energy Coordinator of the date on which
the PST will be conducted at least 30
days prior to such date.
(3) Within 45 days of the PST, the
Company shall submit a complete report
containing all information pertinent to
the PST to the Regional Energy
Coordinator.
(4) The Company shall keep monthly
records of both air quality monitoring
data and air pollutant emissions and
shall submit such records within 15 days
of the end of each calendar month to the
Regional Energy Coordinator. These
records shall detail daily emissions for
all fuel-burning units and shall include
for each unit:
(i) Fuel consumption for each day of
the preceding month.
(ii) Analysis of the fuel consumed
during each week to include sulfur
content, ash content and high heating
value.
(Hi) For the stack serving boiler
number 4. a record of the hourly
measurement of opacity acquired by
means of a continuous opacity
monitoring device.
(5) The Company shall notify the
Director of any exceedance of the
National Primary Ambient Air Quality
Standards within 72 hours of the
collection of such data.
(6) The Company shall notify the
Director within 10 days after each
incremental requirement has been
satisfied. or within 10 days after the
final date set for achieving each such
requirement. if such requirement has not
been achieved.
(d) Violation of any requirement of
this ORDER shall result in one or more
of the following actions:
(1) Enforcement of such requirement
pursuant to subsection 113(a). (h), or (c)
of the Act. including possible judicial
action for an injunction and/or penalties
and in appropriate cases. criminal
prosecution.
(2) Revocation of this ORDER, after
notice and opportunity for a public
hearing. and subsequent enforcement of
the Virginia State Implementation Plan.
(3) If such violation occurs, notice of
noncompliance and subsequent action
pursuant to Section 120 of the Act.
(e) Nothing herein shall affect the
responsibility of the Company to comply
with State. local. or other Federal
regulations.
The entire ORDER is hereby
referenced. Any terms or conditions
appearing in the ORDER and not
contained herein does not excuse
noncompliance by Virginia Electric and
Power Company.
UNITED STATES ENVIRONMENTAL
PROTECTION AGENCY
Region III
In the mailer of: Virginia Electric & Power
Co.. Order No. R-III-CC-004.
This ORDER is issued pursuant to
Subsection 113(d](5) of the Clean Air Act. as
amended, 42 U.S.C. 7413(d) ["the Act"). This
ORDER contains a schedule for compliance.
interim requirements. monitoring and
reporting requirements. and other
requirements of this subsection of the Act.
Public notice has been provided pursuant to
8ubsection 113(d)(1) of the Act. and a copy of
215
this ORDER has been provided 10 the
Governor of the Commonwealth of Virginia
to seek his concurrence.
FINDINGS
On June 30. 1975. Virgmia Electric and
Power Company ("Company") received a
Prohibition Order from the Federal Energy
Administration ("FEA'" pursuant to Section 2
of the Energy Supply and Environmental
Coordination Act of 1974. 15 U.S.C. 792 (Supp.
V. 1975), as implemented by 10 CFR Parts 303
and 305 (1976). as amended. 42 FR 23132
(1977). Said ORDER prohibited. upon receipt
of a Notice of Effectiveness. any further
burning of na tural gas or petroleum products
as the primary energy source for the
Company's Number 4 Boiler.
The Company's Number 4 Boiler was
burning petroleum products a t the time the
FEA Prohibition Order was issued, and if
converted to coal. would no longer be in
compliance with every applicable air
pollution requirement under the Virginia
State Implementation Plan ("SIP"). A
violation of the annual primary ambient air
quality standard for particulate mailer in
Chesapeake, Virginia resulted in a finding by
the United States Environmental Protection
Agency ("EPA'" that, for purposes of this
Order, the Hampton Roads Intrastate Air
Quality Control Region is a nonallainment
region with respect to particulate matter and
that regional limitation was applicable.
The Company, on February 27, 1979.
successfully rebutted the statutory limitation
on the effectiveness of an order. pursuant to
Section 113(d)(5)(D). by demonstrating that.
upon converting Number 4 Boiler to coal. the
source's emi6sions would have an
insignificant effect on the air quality
concentrations in that portion of the region
where particulate matter is being exceeded.
They further demonstrated that conversion to
coal would not contribute to the exceedance
of the national primary ambient air quality
standard for particulate matter in
Chesapeake. Virginia. The Company,
therefore, formally requested from EPA an
order to allow the burning of coal as the
primary energy source. After a thorough
investigation of the information obtained
from all sources, including public comment.
the Administrator of EPA has determined
that the emission limitations. coal pollution
characteristics. and other enforceable
measures contained in the ORDER below.
satisfy the requirements of subsection
113(d)(5)(B) of the Act. Further. pursuant to
subsection 113(d)(5)(B), the Administrator has
determined that compliance with the
requirements of this ORDER will assure that.
during the period of the ORDER before final
compliance is achieved. the burning of coal
by the source will not result in emissions
which will cause or contribute to
concentrations of any air pollutant in excess
of any national primary ambient air quality
standard for such pollutant.
Pursuant to subsection 113(d)(6) of the Act.
the Administrator has determined that the
schedule for compliance set forth below is as
expeditious as practicable.
Finally. Pursuant to subsection 113(d)(7) of
the Act. the Administrator has determined
that the ORDER provides that the source
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41418
Federal Register I Vol. 45. No. 120 I Thursday. June 19. 1980 I Rules and Re~lations
8 RecordJ.~pinll
t. The Company Ihal1 keep monthly
records both of alf quah:y monitonng data
and of all' pol1utant emlSSlona. of wh,ch
records the Company Ihal1 submit copies to
the EPA Region III RegIOnal Energy
Coordmator withm fiheeD (15) daYI of the
end of each calendar month. Said air
pollutant emission record shall detail daily
emissIOn for all fuel-burning unite of the
Company at itl Portsmouth Generahng
Stallon 81 detemllned by application of ErA
emllsion factors and shall at a minimum
include:
a. For each fuel-burning unit. a'breakdown
of the fuel conlumed each day of the
preceding munth:
b. For each fuel.burning unit. an analYlil of
. the fuel consumed each week to include
.ulfur content. ash content and bigh healina
value: and
c. For the Itack-Ierving Boiler Number four
(4) only. a record of Ihe hourly measurement
of opacity. acqUired by meanJI of a
continuous opacity monitoring device, Such a
device shall be inatalled. calibrated. and
maintained in accordance with PerforrnaDce
Speciflce tiOD 1 of Appendix B. Part 60. Tille
40 of the Code of Federal Regulations.
2. If. for any reason. the Company doel not
comply or ",'ill be unable to comply with the
reqUiremeDts of this ORDER. the Company
shall proVIde III wr'!lng to the Director. Ajz.
Toxics and Hazardous Materiala DIVISIOn.
EPA Region Ill. within five (5) day. 01
becoming aware of IUch a,tuallon:
a. A description of the DODcomplianlZ and
iI. cause; and
b, The period during which noncompliance
haa occurred and/or II expected to occur.
and the slepl takeD to reduce. eliminate and
prevent recurrence of the Doncompliance.
3. If the all' quality monitonng data
collected by the Company purauaDt to
Section A of thia paragraph indicatea that the
National Primary Ambient Ajz Quality
Standards for particulates are being
exceeded III the area. the CompaDY shall
notify the Director. Air. Toxica and
Hazardous Matenals Division. EPA Regioo
Ill. of such occurrence by telephone or leller
or other me ana. wi thin aevenly-two (72) houn
of the collection of such data.
4 The requirement of subparagraph 3
hereinabove .hall apply with respect to
monitoring data and the National Ambient
Air Quaht). Standards for Sulfur Dioxide. it
such moni toring requirements are impoeed
punuant to Section A. of thi. paragraph.
VD. Nothing herein shaU affed the
responsibility of Virginia Electric and Power
Company to comply with State, local or other
federal regula tions.
VIll, Virginia Electric and Power Company
il hereby notified that its failure to achieve
filial compliance at its Boiler Number 4 with
the applicable particulate emilsion
regulations of the Virginia SIP by June 30.
1982. or IUch other dale II may be apecified
in a second ORDER pursuant to subsectioa
113(d) of the Act. if issued. may result in a
requirement to pay a noncompliance penalty
under Sechon 120 of the Act Such
requirement may be imposed at an earlier
date. 81 pro\'ided by Subsection 113(d) and
Section 120 of the Act. either in the event Ibat
this ORDER IS temllnated as provided in
Paragraph lX. below. or In the event that an,
reqUirement of thiS ORDER IS violated aa
pro\'ided in paragraph X. below, In any event.
the Compan)' will be formally notified.
pursuant to Subsection 12O(b)(3) and any
regulations promulgated thereunder. of Its
noncompliance,
IX, This ORDER .hall be terminated in
accordance with Subsection 113(d)(8) of the
Act if the Administrator o. his delegate
determines. on the record. after nollce and
hearing. that an tnabihty of the Company to
comply with Rules 2 and 3. Section IV of the
Virginia R~gulations for the Control and
Abatement of Air Pollution. as approved by
EPA. no longer exista ",ith respect to its
Boiler Number 4. In addition. If tbe Company
is able to demonstrate compliance with Rule.
2 and 3 prior to June 30. 1982. then this
ORDER ma)' be tenninated at that earher
date by mutual agreement of the
Administrator and the Company.
X, Violation of any requlI'ement of thi.
ORDER shall result in one or more of the
following acllons:
A Enforcement of such requirement
pursuant to subsection 113 (a). (bl. or Ic) of
the Act. including poslible judicial action for
an injunction and/or penalties and in
appropriate cases. criminal prosecution.
B. Revocation of this ORDER. after notice
and opportunity for a public hearing. and
suhsequent enforcement of the Virginia SIP in
accordance with the preceding paragraph.
C. U. violation occurs. notice of
noncompliance and subsequent actioD
216
punuant to Section t20 01 tile Act
XI. 11Iis ORDER i. effective upon
promulgation in the Federal Resiater and
.fter having received conculTt!nce from the
Governor of Ibe Commonwealth of Virginia.
Dated: June 9. 1980.
Douglal M. Coall.,
Administrator or DeJegat~. U..s.
Environmental Pra~ctJon Agency.
Waiver of Rights To Challenge ORDER
Virginia Electric and Power Company. b,
the duly authorized undersigned. hereby
consent. to the fllldings made and to the
tenns of this ORDER and waives aDY and .U
rights under any provision of law to challenge
this ORDER.
Dated: November 19. 1979.
Moms L Brehmer.
(Authority: 42 U.S.c. 7413(d)J
IFR Doc, 10-11381 Filed 1-1- au -t
BILLING COO( --"1-11
Texas. any gases which exhibit greater
than 35'Jf. opacity, except that a
maximum oC 42" opacity shall be
permitted Cor not more than 8 minutes in
any hour.
(See. t11. 301[a). Clean Ajz Act aa amended
[42 U,S'c. 7411. 7801.))
2. Section 6O.45(g)(1) is amended by
adding paragraph (i) as Collows:
'80.45 EmI88Ion and fuel monltortnt.
. .
(g) . . .
(1) . . .
(i) For source a subject to the opacity
standard oC Section 5O.42(b)(t).
e~ces~ion emissions are defined a. any
slX-nunute period during which the
average opacity oC emissions exceeds 35
percent opacity. except that one six-
minute average per hour oC up to 42
percent opacity need not be reported.
(I'll. Doc 1'1-211151 '...led 1-""'''' us aa)
8IWNG COO( -.01-11
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Federal Register I Vol. 45. No. 220 I Wednesday. November 12. 1980 I Proposed Rulf's
.74i31
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
IA. FRL 166HI
Georgia: Plan Revision Relating to
Georglll Power Plant Harllee Branch;
Approval and PromulgaUon of
Implementation Plana
AGENCY: U.S. Environmental Protection
Agency. Region IV.
ACTION: Proposed rule.
SUMMARY: EPA today proposes approval
action on a State Implementation Plan
(SIP) revision submittal made by the
Georgia Environmental Protection
Division in accordance with the
requirements of Section 110 of the Clean
Air Act. The revision to Georgia's SIP
involves an Enforcement Order for
Georgia Power's Plant Harllee Branch
which was trllnsmitten to EPA May 13.
1980. and was subjected to a public
hearing on January 31. 1980.
DATE: To be considered. comments must
be submitted or. or oefore December 12.
1980.
ADDRESS: Written cumments should be
addressed to Melvin Russell. EPA
Region IV's Air Proj!ram Branch (see
EPA Region IV address below). Copie.
of the materials submitted by Georgia
may be examined during normal
business hours at the following
locations:
Public Information Reference Unit.
Library Systems Branch.
Environmental Protection Agency. 401
M Street. SW.. Washington. D.C.
20460. '
Library. Environmental Protection
Agency. Region IV. 345 Courtland
Street. NE.. Atlanta. Georgia 30365.
Air Protection Branch. Envvironmental
Protection Division. Georgia
Department of Natural Resources. 270
Washington Street. SW.. Atlanta.
Georgia 30334.
FOR FURTHER INFORMATION CONTACT:
Mr. Melvin Russell. Environmental
Protection Agency. Region IV. 345
Courtland Street. NE.. Atlanta. Georgia
30365. Telephone: 401/881-3286 or FrS
257-3288.
SUPPLEMENTARY INFORMATION: Georgia
Power's Plant Branch is at present in
compliance with applicable State and
Federal air quality standards. The
procedure for demonstratinJl r.omDli""ce
with the mass emission limit r.ontained
in GeorJZia Rule 391-3-1-.0212Hdl is
beinJZ altered to enable Units 3 and 4 of
Plant Branch an ahernative method to
demonstrate compliance with the mass
emission limit. In tne eveh1 thaI' 8
quarterly compliance test of these Wuts
indicates emissions of particulate matter
that exceed the limit.
The alternate procedure proposed by
the Georgia Environmental Protection
217
Division W().u1d. not alter the mall!!
emission' limit.. but would allow Units 3
and 4 to demonstrate compliance with
Rule 391-3-1-02(2)(d) by use of a
correlated opacity test procedure. Under
the alternate procedure Units 3 and 4
must be operated at all times. such that
the opacity from the common stack shall
not exceed a correlated opacity which
corresponds to the mass emission rate
which complies with Rule
391-3-1-.02(2]( d).
The correlated opacity was
determined through a series of stack
tests in which opacity and mass
emission rates were measured
simultaneously. It was petermined that
4Q2£. opacity far Units 3 and 4 wi I Lass.ure
compliance with the mass emission
I'mlt.
This alternate procedure for
demonstrating compliance with Georgia
Rule 391-3-1-.02(2](d) will be accepted
as an interim procedure. and may not be
used beyond December 31. 1982.
EPA has reviewed the data
establishing the correlated opacity and
found it to be acceptable. EPA.
therefore. proposes to approve Ihis
revision to Georgia's State
Implementation Plan.
ISection 110 of the Clean Air Act (42 U.S.C.
7410))
Dated: October 28. 1980.
Rebecca W. "arunl..
Regional Adminislralor.
(FR Doc ~J5229 riled 11-'1>-<10: 8'45 oml
8IWNG CODE 6560-38-M
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%18
Fedel'8l Register./ Vol. 46. No. 5 I 11unday. January 8. 1981 I Noticew
ENVIRONVEHTAL PROTECT1ON
AGENCY
(AIH'RL M7WJ
. Collection 0' SO. Erntssfons Data From
Certain Coal-Ared Elec:t1lc UtJIItJ
Steam Generating Units
AGPCY: U.s. Environmental Protection
Agency (EP A).
ACTION: Notice.
SUMMARV': The purpose of this Notice i.
to announce a one-year program being
considered b, the Administrator to
expud the availability of mort-term
so. emissiona data from cel'taiD. coal-
fired electric utility steam generaq
unit. and to invite couunent on the
intended program before it ia made final.
The program would require. under
authority granted to the Administrator
by Section 114 of the Clean Air Act. that
utilities report the :U-bour (daily) So.
emission rate (lb. 50./10' Btu) and the
daily heat input (10' Bin) for each coal-
fired .team generator capable of firins
at least 3,000 millioo Btu/hr heat input
(300-MW potential electrical output
capacity). Utilitiea wiD be aDowed to
use continuous (and possibly
intermittent) emis.ion monitoring or fuel
sampling and analysis methods to .
determine the required emissiona
information in accordance with criteria
set forth by the Administrator.
Today'. Notice describe. the basis for
the one-year program under
consideration and presents the tentative
requirements which would have to be
met in complYinl with the program.
Final requirements wiD be established
after the Administrator ha. had an
opportunity to consider the comment.
received pursuant to !hi. Notice.
DATEI: EPA will con.ider comments
received on or before March 9. 1981.
ADDRESS: Comment. .bauld be
submitted (in duplicate. if possible) to:
Central Docket Section (A-130), U.s.
Environmental Protection Agency, 401 M
Sl SW. Washington. D.C. 20460.
Attention: Docket No. OAQPS-79-1Z.
Docket No. OAQPS-79-1Z, containing
material relevant to thi. Notice. i.
located in the Central Docket Section of
the U.s, Environmental Protection
Agency, West Tower Lobby Gallery L
401 M Sl SW. Washington, D.C. 20460.
The docket may be inspected between
8:00 a.m. and 4:00 p.m. on weekdays and
a reasonable fee may be charged for
copying.
FOR FURTHER INFORMATION CONTACT:
Joseph Sableski Of Daniel deRoeck.
Plans Guideline. Section (MD-15). Us.
Environmental PrOtection Agency.
Research Triangle, Part. H.C. 2T111:
Telephone No. (919] 541-5437. or (FI'S)
629-5431.
SUPfIUMEJfTARY IIIFORIIA noN:
I. Background
The Administrator of the U.s,
Environmental Protection Asency i.
considering the implementation of.
one-year reporting program applicable
to coal-fired electric utility .team
generating units. The program, requiring
the submission of daily SO. emissions
data. would enable the Agency to
slgnificantJy Improve Its ability to define
the emissions from power plants and
would provide a data base to more
effectivel, assess the environmental
Impact. of 50. emis.iona.
Relatively little short-tenn so.
eminions data from power plant. are
CUJTently available. While several
special studies of short duration have
been made on individual plants, EPA'.
main data base defines annual average
SO. emisslona. The interpretation of
short-term average. using long-term
average. ia very difficult at best because
of the tendency for power plants burning
coal to experience highly variable
emissions, especially over short
averaging periods of 24 hours or less.
This emissions variability results from
the natural variation in the sulfur
content of coaL In recent years there has
been a growing awareness of the
problems associated with sulfur
variability in developing meaningful
emission limits and detennining
compliance for coal.fired sources. The
data that would be acquired through the
program being considered by the
Administrator could assist the Agency
in its planned review of existing policie.
and procedures for developing.
evaluating. and enforcing emission
limits for coal-fired power plants (~5 FR
9994. February 14, 1980).
SO. Emission Limit! for Power P!ants
Traditionally, the setting of emission
limits for coal.fired power p!,mts has
been done without allowances for sulfur
variability. Mathematical d;~;.'f',~ion
models used to predict grour.d.I,,"el
concentrations of SO. have gen~rally
assumed a constant emission rate. The
predictions from these models were then
used to develop emission limits which
typically did not specify an averaging
period over which the limit would apply.
As a result. the tendency has been !hat
such inadequately-defined emission
limits are interpreted inconsistently and
are usually not applied to short.tenn
periods such as 24 hours or less.
EPA is evaluating variou. alternative
methods for establishing emission limits
for power plants. In some cases, the .
methods make specific allowances for
218:
-------
Federal Register / Vol. 46, No, 5 / Thursday. Janudry 8. 1981 / Notices
2187
~ulfur \'iHl~b;li!y. In a:1\ Hen I it is clear
thai meuningful emi~sl~n hnlJls must
spp('if~ a\ PI a~ing periods OHr which
the limit will arr'l~ Add:l1un..lly. the
Ag,'n('~ L,JI!'\l'~ th,tI Ih,' avt.r..ging
pf'JH.d ~h"lIld 1)1' .1l1':jI"I'" to
dI'IIH1f1'trut!' prutl" lion of the amhi,'nt
stanJ,!ru'
am' of the ilpprourhps Lein~
e\ alunled in dudes a mudciir.g te(.hnique
that,pp!iJr.es the constunt emission rate
with a distribution of SO, ('mission rates
to detern:me statislicall~ tb!. .!ir qualit~.
imp.H-'that n.ay n:sult. [45 FH 99YG.
Fcb,u;!r~ 14, 19GO). Anuther approach.
which is uln:,.dy bl ing app1icd by some
States. is to set a 24-hour maximum limit
",;jth s('\'(r,,1 exceptions allowed per
month. Alsu, a number of States and
ind,.:,lri,'s hav'c r('commcnded a 30-da~'
aHra~i~g period. While the Agency
does notl'ndorse any sllch approaches
for j!eneral app1ication at this time, the
availability of an emissions data base
defming the short-term \'ariability of SO.
emissions is an important element in
appraising thr implirations of various
alternati\l' approa(.h('s for setting futurl'
SO, emissiun lin,;ls.
Cnmplianr:e Status of POl\'cr Plants
As tl". tn'nd for enfdrcelnent
pmgr",ns muves aw,lY from delermining
compliimce on an infrequent basis and
tuwards continuou~ determination of
compliance, the rouline availabilit~' of
data beromes an important
consideration. Routll1c data collection is
espl'cially important when enforcing
regulutions for sourrcs whose emissions
tend to vary even under constant
operating loads.
II. Proposed Program
The program being considered by the
Administ. ator would require the owners
or op,'r., ,urs of prescribed coal-fired
electric utility steam generating units
(see Affected $ources below), to
calculate and report to EPA the
following information:
1. SO. emission rate (lb.SO./10ply to utilities huv ing cuntmulHlS
emission monilors that pro\ ide d~ta on
as short a time fra;ne as 15 minutes.
One way to expedite the Agency's
acquisition of short-ter;n d~ta is to
estubl:sh retroactin rep::>rting
requirements That is. utilities wo~ld be
required to d. termme their daily 24-hour
emission rale for a one year period
which has already commenced. e.g..
January 1 to December 31, 1980 In order
for this to be feasible, utilities must have
adequate historical data from which
emission rates and heat inputs can be
determined. Therefore, this notice
solicits comments on the availability of
hi~torical data retained by utihties, and
the time that would be ne'eded to review
such data and make the appropriate
daily detrrminations.
Affected Snurecs: Coal-fired electric
utility steam generating units having a
polential electrical output capacity of
300 MW (3.000 million Btu/hr input)
\0\ ould bp subject tu the requirempnts of
the proposed program. Infonnation
a\'ailable to the Agency indicates thdl.
based on this cutoff sizp, approx.imutely
225 coal-fired steam generators would
be affectpd. These units accollnt for
about half the SO, emis,ions produced
b~' the electric utilify industry. The
Administrator bel,ev'es that the selected
cutoff size would serve to minimize the
burden on the electric utility companies
and keep the amount of data recei\'ed
by EPA to a manageable level. while
providing the Agency with a meaningful
data base.
Sompling Afethods: The Administralur
intends to accept SO. emissions
infonnation that is derived from either
continuous emission monitoring or fuel
sampling and analysis methods. He is
also considering another method, known
as intermittent monitoring: this method
is furlher discussed below.
An affected coal-fired steam
generating unit that has inslalled a
continuous monitor to comply wilh
Federal (40 CFR Part 60) or Stat.
regulations 10 install and operate a
continuous emission monitoring 6ystel1l
for SO. must use !Bat system as thl!
ba sis for calcula ting the required
emissions Infonnation. The progrelJl
described herein does not atlemplto
impose additionallnOnitorina
requirements for continuous monitoring
on utilities, but it wlU specify thHt
required monitors be calibrated and
219
op.oratl'd in accordance with the
applicable regulations.
Table 1. Summaf\' of Information
Rl'quired by Proposed EPA Program
QIIl:rtl'fI'r R,'ports
. 24-hr.[d"ily) I'mission r,,'" (lh S()I
lU"lJtl.j
. 24-hr. [dail)) heat ir.put [1n' DIl.l
Initi,,/ Rrport Only
1 Suurce Information:
. Company name and addrl'ss
. PI.lllt name and address
. Unit 10.
. HI'"t input capacit~ /Potential
electrical output capacity
. r\ame and titlp of reporting official
2. Emissions Chararterlzalion
Informa tion:
. Type(s) of coal used (Bituminous, etc )
. Source of coal [Bureau of Mines Coal
Districts)
. Standard sampling method (CEM vs.
coal sampling and an"lysis)
. Identification of ASTM procedures,
where applicable
. Use of nue gas dl'sulfurization
. Use of coal cleaning methods
""'here continuous monitunng is not
cum'ntly requirl'd and instull"l~, SO,
emissions from affected coal-fir. d ~"'''m
generutors would ha\'e to be estIIJ:"'I'd
from the collection and an.llysis of d"iI)
coal samples. The Administrutor 10
mindful of the comments recl'i, l'd fru!11
utility represent"tives in respo"'I' Ie; till'
Ad\'ance Nolice of Proposed
Rulemal..ing entitled "Emission
Monitoring of Stationary Sources" (44
FR 46481, August 8, 1979). Those
comments strongly sugges\pd that fud
sampling and analysis techniquc's could
be used to determine SO. emissions 111
lieu of continuous monitors.
EPA is continuing its investigation of
the need for requiring continous
monitoring for existing coal-fired slc'am
generators, but intends to examinl' the
feasibility of allowing other methods.
8uc:h as fuel sampling and analysis.
where they are shown to be accepldblC'
alternatives. The fact that the propused
program would allow the use uf fll"}
sumpllllg and analysis ferhniql"" dp,',
nol imply that they "ill be pJ"Judt:n! '"
acceptable alternatives for future
regulatory programs; however, the
Administrator m"y b. .bl. to use the
data 10 assist in milkinll tbat kind of
dpc.ision at a later date.
The main steps in a fuel s8mplin~ and
analysis program include (1) collecllUn
of a rl'pressntali\'e umple, (2)
preparation of the s~mpll! for /\nul) bl~,.
and [3) analysis of the lample for ito
essl'ntidl components snd helll Lonli'nl.
Infurmation avatlable to EPA indlcut,.,
-------
2188
Federal Register I Vol. 46, No.5 I Thursday. January 8. 1981 I Notices
,
that many. illlDt most.. utilities generaUr
follow standard testing procedures .
publ:shed by the American Sociely or
Testir1g ~faterials (ASTM]. Therefore. in
a manner consistent with current
industry practices, the Administrator
intend5 to specify that utilities use the
following methods to collect, prepare,
and analyze their coal samples:
°ASn.1 O-ZZ34 (Standard Methods for
Collection of a Gross Sample of Coal):
-ASTM 0-2013 (Standard Method for
Preparing Coal Samples for Analysis);
-AST\\ 0-3177 :Standard Test
~fethod for Total Sulfur in the Analysis
of Coal and Coke), Dr an acceptable
automatic analytical device;
-".ST~f 0-2015 (Standard Test
Mf'lhod for Gross Calorific Value of
Solid Fuel by the Adiabatic Bomb
Method).
A very difficult step in the fuel
samp!lng and analysis program is the
;nlt',11 step of collecting a representati\'e
gross ,,,.: chdr .cler or the coal. the number
c"d ." ~~,:s or Lncrrmenu, and the o\er.all
r"t'c.c;' n reqUlr?d.
TheS. ASTM 0-2234 is actually a
serie, lIf methods that are classified
accorJ1ng to the rel:.Ibility of each
,rodi\" J"dl method. Classifications are
Lased upon the type (human discretion
\" 5 nJ ~uman discretion) of increment
I.l":,L:,on. the conditions (e.g.. full
,treaD cut. part stream cut) of increment
collectl(1n. and the kind of intervals or
spac1r~ [5) stematic vs, random)
bel\"\ t!cn Il~crements, Accordingly, the
0'.\ ';t" lr operator of each affected
sle3n' ,,"r:eratar will be expected to use
:~e " reli~ble classification method
,~:;t L ~ ~ea'l()nably be apphed without
m.I' ,r ,penJllure and equipment
".( "ent!:y the utility.
L': :,29 Will be expected to collect. to
,~" ex '0'11 feaslb!e, samples of coal on a
j,u\ "3sf:red" basis. "As-fired" is
In', r;~~:eJ here to mean that the sample
" I "::"l 'pJ from the coal stream just
prior kJ fillin. the bunken (01' liloa) or 8t
any point downstream of the tnmkers
before it il conveyed to the combustion
chamber of the boil«.
Whe~ -as-fired- .ampl~ is not
feasible. utilities would have to estimate
their daily emissions on the basis of
sampling performed at other locationa.
In most instances. where an "as-fired"
sampling procedure cannot be
implemented, coal wiU be sampled when
it is received from the supplier or mine
prior to storage for later use. Utili tie.
must apply their best engineering
judgment when ba.ing thei!' emission
estimates on "as-received"' samples
since thele coal samples generally win
not be representative of the coal which
is actually burned during any particular
day.
The methodl involved in the
preparation aDd analysi. of coal
samples appear to be mo~
straightforward than thole for collectin&
the grosa sample. Preparation and
analysis methods are not dependent on
the differences in individual coal
distribution aysteau from one plant to
another. Consequently. these methoda
are more readily standardized. One
disadvantage of the ASTM method for
sulfur analysis. however. is that it
generally takes several hours to
complete. For this reason. a number of
utilities have switched to an automated
analytical device so that sulfur content
CJn be determined much more rapidly,
Therefore. where such automated
devices are used. the Administrator
intends to accept them in lieu of the
standard ASTM method.
As mentioned above. the
Administrator is also considering
intermittent monitoring a. a method for
determining SO. emmissions under this
program. In this method. the So. is
collected by an in-stack sampling train.
captured in a solution. and analyzed.
The opera tion of the train ia controlled
intermittently by a timer or on a
continuous basis by a pump with a low.
constant flow rate. This method would
allow an extended sampling period (in
this case. 24 hours) and the
determination of the average SO.
emission rate for that period. As of this
wrdin;:, EPA is preparing a notice that
would pmpose the intermittent
rr.on.toring method as an acceptable
procedClre for compl.oilce with
~ 60 47a(f) of 40 eFR Part 50. Subpart
DA: Subpart DA covers new source
performance standards for fossile fuel-
fired steam electric plants. Paragraph (f)
rp!juires that an the event of a
220
breakdown i.D the contitwoua em.iaion
moaitoring system, emiuiOll data must
be obtained by other monitorins system.
or reference methods approved by EPA.
EmissioR Cfllculati0tf8
(1) Utilities would be required to
calculate a daily average emiS5ion rate
through the use of continuous emission
monitoring or coal sampling and
analysis methods for each affected coal-
fired steam generator according to the
following procedures:m urage
(i) For continuous emission
monitoring. the hourly SO. emisaion rate
is to be arithmetically averaged for each
hour of boiler operation per day. The
hourly emission rate. are calculated
according to the procedures in 40 CFR
60.45 (e) and (f). .
(iil For coal sampling and anal)'lis.
the following equation is to be used:
E
104
2.0(%5)
GCV
=
x
Where:
E = Daily sulfur dioxide emission rate
from fuel analysis: lbfmillion 8111.
%5 = Sulflll' content of daily fuel
supply. on a dry basis; weight percent.
GCV = Gross calorific value of daily
fuel supply. on a dry basis; Btu/lb.-
(2) Values for the 24-hour (da:!y) heat
input. expressed in million Btu's per day.
could be determined directly from
knowledge of the gross calorific value of
the coal and the amount of coal
consumed duri!1g each daily 24-hour
period. However. where information
pertaining to the d.:liIy tonnage of coal
consumed cannot readily be dp'!!rrnined.
it is more likely that ul.litiel will depend
upon daily megawatt production data
which can be converted to a daily heat
input value when the efficiency of the
boiler is taken into account. TI.e
Administrator intends to accept eIther
method for determining the daily heat
input.
Additional Consideration: In addition
to comments on the program descnbed
above. EPA is also interested in
obtaining comments on the following
indirectly related matter.
In the Federal Register of October 6,
1975, EPA promulgated regulations
requiring continuous emilsion
monitoring on certain source ca tegorics
under Part 50 (New Source Performance
Standards) (40 FR 462501. Subpart D of
that regulation allows rossll fuel-fired
steam generator. without flue gas
desulfuTlzation units to use conlinuous
emission monitors or fuel samphng and
analy~is to detemline so. enllssions. At
-------
Federal Register I Vol. 46. No.5 I Thuraday. January 8. 1981 I Notices
2189
the time of promulgation. however. EPA
concluded that a meaningful Cuel
analysis procedure could not be
developed that would be adequate or
consistent with the then.autent Cuel
situation. EPA indicated that Curther
study was necessary to speciCy a
procedure. Facilities that elected to use
fuel analysis instead of continuous SO.
monitoring did not actuaUy have to
begin sampling and analysis un~~ EPA
published a sampling and analysIs
procedure. Therefore. a gap currently
exists in the Federal regulations.
Nevertheless. almost aU utilities which
are buming low sutrur coal to meet the
NSPS are reportedly analyzing coal
sample and in many cases they are also
monitoring SO. in stack gases. EPA is
thereCore posing another question in this
notice on the feasibility oC requiring
power plants to use the data obtained
Crom Cuel analysis in preparing excess
emission reports.
III. Program Authority
Section 114 oC the Clean Air Act
provides administrative authority Cor
EPA to require the owner or operator of
any emissions source to report its
emissions and any other information as
may be reasonably required by the
Administrator. The Administrator
believes that the one-year program
being considered is an appropriate use
of Section 114 in that the data which
would be required will be used by the
Agency to evaluate techniques Cor
setting So. emission limits and to orient
and priori!ize new enforcement
initiatives to bring sources into
compliance with the requirements of
implementation plans.
In light of the nationwide impact of
the requirements. the Administrator is
announcing his intentions so that
utilities and other interested perlWns
may respond After all relevant
comments have been considered the
Administrator wiU announce the Cinal
program in a subsequent Federal
Register Notice. However. each utility
will be sent a certified letter citing the
authority under Section 114 which will
require that the prescribed emissions
information Cor affected coal-fired steam
generating units be reported to EPA.
Utilities will be required to provide a
written acknowledgement of receipt of
the Section 114 letter to EPA.
IV. Comments
The Administrator invites general
comments on the overall program
described in this Notice. Also. he is
particularly interested in comments
pertaining to coal sampling and analysIs
methods and the extent of their use by
utilitie!O. In order to direct commenters
to specific areas of interest. comments
should address, but not be limited to. the
following:
1. What are the specific problems
associated with estimating the daily
SO. emission rate on the basis of "a5-
received" coal samples?
z. What additional costs will be
incurred in order to collect and analvze
daily coal samples? .
3. What types of modifications to
existing coal sampling systems would
ha ve to be made to increase their
reliability (based on ASTM
classification)?
4. What procedures are used to assess
the reliability of current coal sampling
methods?
5. How often is the steam-electric heat
rate evaluated?
221
6. Does the heat rate vary significantly
from day to day?
7. Is daily coal consumption data (I.e..
tons of coal burned per day) routinely
documented?
8. What additional costs would be
incurred to make the required
determinations of daily SO . emission
rates and heat input for the one. year
reporting period?
9. Is adequate historical data
available to determine the daily SO.
emission rate and heat input Cor the one.
year period beginning January 1. 1980?
How much time would be needed to
make the necessary determinations
based on historical data?
10. What duplication of burdens witb
other Sta te. local or Federal
requirements would result from
compliance with the proposed
requirements?
11. What has been control agency
experience with the use of fuel analy.i.
data to estimate emissions?
12. For those lOIIJ'Ce. with continuous
emission monilors. what additional
costs would be incuITed to make the
required determinations of SO.
emission rates and heat input, on a 3
hour basis. for the one-year reporting
period?
13. What financial and technical
problems are incurred if EPA specifies
as.fired fuel analysis as described in 40
crn Part 60. Appendix A. Method 19.
Section 3.3 as the acceptable fuel
sampling method of 40 crn Part 60.
Subpart D. Section 60.45 for the
purposes of reporting excess emissions?
Dated. December 29,1980.
Douglas M. Coolie.
Admmistrator.
IFR Doc. 81~12 FII~d 1-1-81.8.45 8ml
BILUHG CODE --
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-
Monday
January 26, 1981
Part IX
Environmental
Protection Agency
Standards for Performance for New
Stationary Sources; Revisions to General
Provisions and Additions to Appendix A,
and Reproposal of Revisions to
Appendix B
223
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83:;~
Federal Register I Vol. 46, No. 16 I Monday. January 26, 1981 I Proposed Rules
ENVIRONMENTAL. PROTECTION
AGENCY
40 CFR Part 60
I AD-FRL 162!>-7 J
Standards ot Per10rmance tor New
Stationary Sources; Proposed
Revisions to General Provisions and
Addillons to Appendix A, and
Reproposal 01 Revisions to Appendix
B
AGENCY: Environmental Protecllon
AF' '.r y (EPA).
ACTION: Proposed Rule and Nollce of
Pd'.' Heanng
SUMMARY: This proposed rule (1) revIses
It.' r. .r.llonng requirements (160 13) of
thi' C' .,eral ProvIsions. (2) adds
M"'~.'.J{Js 6A and 6B to Appendl" A. and
(.I! It proposes re\'islOns to Perfonnance
Sf'" .f,rations 2 and 3 to Appendix B of
40 CTR Purt 60. The proposed revisions
,,, 11.0 13 are bemg made to make this
~p I,,,n consistent with the proposed
rl'\ '''O:1S to Appendix B. Methods 6A
01 ; ,,:-> are being proposed because they
~I~';",h the detennination of the SO,
(." .",,;n rates in terms of ng/)
I',." ,'mance SpecificatIOns 2 and 3
fI \ ".ons are being reproposed because
tr.!. changes that have been made to the
p,..r",mance specifications as a f('sult of
, ,," "'f'nts recl'ived on the original
pr:'j'."d! of October 10.1979 (44 FR
5I1h('~1 are substantial and involve an
ent:rt'ly new concept.
DATES: Commer.13 Comments must be
rpr ", ,ed on or before March 27. 1981.
I'" f,!ic Hearing A public hearing will
10,. h~ld on February 19, 1981 beginning
HI ~.I m
Ii".;ues//o SpeaA a/ Heanng<
I'prs,1ns wishing to present oral
t('~t.;nony must contact EPA by
hk""ry 12. 1981 (1 week before
h,..,-:ng).
AOD~ESSES: Comments. Comments
sh",.'d be submitted (in dupltcate if
pos"lJle) to: Central Docket Section [A-
13()1 Attention Docket Number
0/\QP~79-4. U.S. Environmental
ProtectIOn Agency. 401 M Street. SW..
Washngton. D.C. 20460.
f': :,lic Hearing The public hearing
wi!' !'c held at Emission Measurement
Lal ory. R.T.P. North Carolina. Persons
"" 'g to present oral testimony should
n(ll.' Ms. Vivian Phares. Emission
Mt"'~Jrement Branch {MD-13J. U.S.
EI1\ :ronmental Protection Agency.
RE'search Triangle Park. North Carolma
27711. tE'1ephonp number (919) 541-54::3.
D.'cAe/ Docket Number OAQPS-79-4
(I'<'rf,'rmance SpecIfications 2 and 3)
IInd [h1Cket Number A-6(}..3Q (Methods
6A Hnd 6BJ. containing supporting
infonnation used in developing the
proposed rulemaking are located in the
US. Enviromental Protection Agency.
Central Docket Section. West Tower
Lobby. Gallery 1. Waterside Mall. 401 M
Street. S.W.. Washington. D.C. 20460.
The docket may be inspected between 8
a m and 4 p.m on weekdays. and a
reasonable fee may be charged for
copying.
FOR FVATHER INFORMATION CONTACT:
Mr. Roger T. Shigehara (MD-19J. U.S.
Environmental Protection Agency.
Research Triangle Park. North Carolina
27711. telephone number (919J 541-2237.
SUPPLEMENTARY INFORMATION: The
dIscussion in this section has been
divided into three separate parts. Part A
discusses proposed changes to the
G~neral Provisions of 40 CFR Part 60.
Part B discusses the addition of
proposed Methods 6A and 6B to
Appendix A. and Part C discusses
reproposal of revisions to Performance
Specifications 2 and 3 to Appendix B.
Part A
The proposed revisions to 160.13 of
the General Provisions are being made
to make this section consistent with the
proposed revisions to Appendix B. Since
the reproposal to Appendix B uses the
concept of evaluating the continuous
emission monitors as a system. based on
relative accuracy test results. the use of
certified cylinder gases. optical filters, or
gas cells is not necessary. The
requirement for quantification of the
zero and span drifts is not a change. but
a clarification of what is required under
the existing perfonnance specifications.
Part 8
Two reference met~ods (Methods 6A
and 6B] are proposed. Method 6A.
"Determination of Sulfur Dioxide,
Moisture. and Carbon Dioxide
EmissIOns from Fossil Fuel Combustion
Sources," combines the sampling and
analysis of SO. and CO.. The SO. is
collected in a hydrogen peroxide
solution and analyzed by the barium-
thorin titration procedure described in
Method 6. The CO, Is collected by a
.olid absorbent and analyzed
gravimetrically. The .ample gas volume
Is measured to allow determination of
SO, concentration, CO. concentration.
moisture. and emission rate from
combustion source. in nan: U the only
measurement needed i8 In terms of
p.mission rate or if the CO. and moisture
concentration. are not needed. e.g.. to
convert NO. coru:entration to "II', the
volume meter I. not required. It i.
intended that Method 6A be u.ed 88 an
alternative to Methods 6 and 3 for the
224
purpose of determining SO. emission
rates in ",IJ.
Method 68. "Determination of Sulfur
Dioxide and Carbon Dioxide Daily
Average Emissions from Fossil Fuel
Combustion Sources," employs the same
sampling train and analysi8 procedures
as Method 6A, but the operation of the
train is controlled on an intermittent
basis by a timer or on a continuous
basis by u.ing a low. constant flow-rate
pump. This allows an extended
8ampling time period and the
determination of an average value for
that time period of SO. concentration.
CO, concentration. and emi8sion rate
from combustion sources in "l1J.
Method 6B is proposed as an acceptable
procedure for compliance with 1 6O.47a
(f) of 40 CFR Part 60. Subpart Da. This
paragraph (f) requires that in the event
of CEMS breakdown, emission dala will
be obtained by using other monitoring
systems or reference methods approved
by the Administrator.
Part C
Revisions to Performance
Specifications 2 and 3 for the initial
evaluation of continuous emission
monitoring systems (CEMSJ for SO..
NO.. and diluent gases were proposed
on October 10. 1979 (44 FR 58602).
Comments received as a result of this
proposal led to reevaluation of the
provisions and a change in the overall
approach to the perfonnance
specifications. The reproposed
perfonnance specifications deemphasize
instrument equipment specifications and
add emphasis to the evaluation of the
CEMS and its location as a system. The
specification requirement. are limited to
calibration drift tests and relative
accuracy tests. The acceptability limit8
for relative accuracy remain the same as
in the previously proposed revisions 10
the perfonnance specifications.
CEMS guidelines will also be
published in a separate document at the
time of proposal to provide vendors.
purchasers. and operators of CEMS with
8upplementary equipment and
performance 8pecifications. The
guidelines will contain additional
procedures and specifications that may
provide further evaluation of the CEMS
beyond that required by Performance
Specifications 2 and 3. e.g.. response
time. 2-hour zero and calibration drifts.
8ampling locations. and calibration
value analyses.
Applicability
The prop08ed revision8 would apply
to all CEMS currently subject to
Performance Specification8 2 and 3.
These include sources subject to
.tandard. of performance that have
-------
Federal Register I Vol. 46, No. 16 I Monday, January 26, 19B1 I Proposed Rules
8353
already been promulgated and sources
subject to Appendix P to 40 CFR Part 51.
Since the requirements of the
reproposed performance specification
revisions are limited to daily calibration
drift tests and relative accuracy tests,
existing CEMS that met the
specifications of the current
Performance Specifications 2 and 3 also
meet the requirements of these revised
specifications and, therefore, do not
require retesting.
This reproposal bas retained the
definition of a "continuous emission
monitoring system" and includes the
diluent monitor, if applicable. This
definition requires the relative accuracy
of the CEMS to be determined in terms
of the emission standard. e.g., mass per
unit calorific value for fossil fuel-fired
steam generators. Several commenters
felt that the limits of relative accuracy
should be relaxed from the present 20
percent because of the addition of the
diluent anaJ)'zer output. Others added
that errors with the manual reference
methods could increase the possibility
of poor relative accuracy determinations
now that an additional measurement is
required. The Administrator has
reviewed a number of relative accuracy
tests and has concluded that the
variations in the manual reference
method determinations are not the
major cause of failure, but that the
difference between the mean of the
reference method and the CEMS values
is the most probable cause. This
situation is correctable.
Comments OD Proposal
Numerous commenters noted that the
proposed revisions go far beyond
clarification and considered them as
significant changes. A large part of this
concern was because they felt that
many existing CEMS were not installed
according to the proposed install a tion
specifications. In addition, many
commenters felt the need for greater
Dexibility in selecting alternative GEMS
measurement locations. Several
commenters desired the inclusion of test
procedures to evaluate single-pass, in
situ CEMS. Others objected to the length
and cost of testing. Opposing views
were presented on the need for
stratification checks. Many commenters
dealt with specific parts of the proposal
and a few raised issues beyond the
scope of the revisions. Because the
Administrator has changed the overall
approach 10 performance specifications
as mentioned in the beginning of Part C,
many of these comments no longer
apply and many of the objections have
been resolved.
The quality assurance requirements
for GEMS and associated Issues were
raised by many commenters. Most
commenters stated that there was a
need for EPA to issue guidelines or
requirements for quality aS9urance. EPA
is developing such procedures, and they
will be published later this year or early
next year as Appendl,( E to 40 CFR PaM
60. Some commenters erroneously
assumed that the quali ty assurance
procedures were an integral part of the
specifications. Although related, this
spEcification should be evaluated on the
basis of its adequacy in evaluating a
CEMS after their initial installation.
The reproposed performance
specifications include a pro\;sion that
the relative accuracy of a CE.to..fS must be
within :f:20 percent of the mean
reference value or :f:10 percent of the
applicable standard. whichever is
greater. Several commenters endorsed
this change, while one felt the change to
allow an accuracy of :t:10 percent of the
applicable standard is too lenient at low
emission rates. The Administrator feels
that it is restrictive to require a high
degree of relative accuracy when the
actual emission levels are equivalent to
50 percent or less of the applicable
emission standard.
Request for Comments on Other Views
A number of suggestions were
received which were not incorporated in
these revisions. Because they represent
differing views. EPA requests com.ments
on them to determine what course of
acti...- »hould be taken in the final rule
making. The suggestions are as follows:
1. Sf:ction 6O.13(b) was revised to
exclude the mandatory 7-day
conditioning period used to verify the
CEMS operational status. Once
commenter feels that the mandatory
conditioning period should not only be
retained, but should be made longer
depending on how the CEMS is used
(i.e., for operation and maintenance
requirements or for compliance/
enforcement purposes) as follows:
a. The presently required 7-day
conditioning period should be retained
for CEMS used for operation and
maintenance requirements.
b. If the CEMS is used for comphance/
enforcement purposes. a 3o-day
conditionihg period should be required
and that the relative accuracy tests
should be spread over 3 days instead of
one.
e. All CEMS. whether for operation
and maintenace requirements or for
compliance/enforcement purposes.
should be installed and operational for
60 or 90 days prior to the initial NSPS
tesl.
If the above are done, the commenter
feels that (1) the owner/operator/agency
would be aware of the progress made by
225
the control system in complying with the
emission standards, (2) there would be a
greater chance of the CEMS passmg the
performance specification test and of
the facility complying with the
regulations wittin the time requirements
of ~ 60.8. and (3) the operator/vendor I
tester/age:!ty would mmimize loss of
valuable reso'J.!'ces and time.
2 Onre commenter feels that
~ 60 13[c) should require all CE.\IS
Performance Specification Tests to be
done concurrent with NSPS tests under
~ 60.8. This would streamline the
process and save resources for owners
and agencies alike.
3. Section 6O.13(d) was revised 10
delete the requirements listed under
(d)(l) and [d)(2) because EPA felt that
the relative accuracy test would va:,date
the CEMS system which includes t~e
calibration gases or devices. One
commenter, however, feels that the
requirement to introduce zero and span
gas mixtures into the measurement
system at the probe at the stack w~1I
should be retained and conducted in
such a way that the entire system
including the sample interface is
checked. This requirement would
provide a means to check tbe CE"S on
a daily basis. in addition the commenter
feels tllat the requirement for checking
the calibration gases at 6-month
Intervals may be deleted provided that
the vaJues used for replacement gas
cylinders. ca:ibration gas cells or o;:>tical
filters are approved by the control
agency.
4. One commenter reels that tr.e
following specifications should be
added in Section 4 of Performance
Specification 2:
a The CEMS relative accuracy should
be relaxed by using a sliding funcll,l:! of
the allowable emission standard and/or
the reference method tests for vel)' low
emission limits, e.g., 0.10 pounds per 10'
Btu emission limit under PSD permits.
b. Each new compliance/enforcement
CEMS installed after 1983 must have an
external means of checking the
calibration of the instrument using
separate calibration/audit materials
c. A minimum data recovery
specification of at least 18 hours in at
least 22 out of 30 days (or simil.n)
should be included. This would mean
that a performance specification test
would not be officially completed until
after the 30 days.
5. One commenter feels that EPA
should consider using Section 7.1 of
Performance Specification 2 to specify
that during the CEMS performance
specification test all data be recorded
both in separate units of measurements
(ppm and percent CO. or 0,) as wdl as
combined units of the standard.
-------
8354
Federal Register I Vol. 46, No. 16 I Monday, January 26, 1981 I Proposed Rules
Appndix A--.r--,... M8tb0d8
8. In Performance Specification 2. the
definition or "Relative Accuracy" i.
incorrect In.tead or a degree or
correctne.s. It i. actually a measure or
"relative error." One commenter reels
that "relative accuracy" .hould be
changed to "relative error."
7. In Section 7.3 or Performance
Specification 2, the tester Is allowed to
reject up to three samples provided that
the total number or test result. used to
delermine the relative accuracy i.
greater than or equal to nine. EPA had
considered using statistical techniques
to reject outliers. but round that these
techniques were too restrictive. One
commenter reels that .tatistical
techniques .hould be used. At a
mmimum. the cornmenter reels that the
conlrol agencies should be consulted
before any data is rejected.
Miscellaneous
Authority: Thi. propo.ed rule mal
-------
Federal Register I Vol. 46. No. 16 I Monday. January 26. 1981 I.Propo8ed Rules
8355
1YSTACK WALL
'ROBE (END PACKED '
WitH QUARTZ OR
PYREX WOOl.
I!IILlING COOl -a<:
THERMOMETER
MIDGET BUBBLERS
Figure 6A-1. Sampling train.
SURGE TANK
227
-------
8356
Federal Regi8ter I Vol. 46, No. 16 I Monday. January 26. 1981 I PropQ.led Rulaa
-
31.1 Dn'erlte." Anhydrou. calcium .ulCate
(CaSO,) de.iccant. 8 me.h.
3 ].2 A.carite Sodium hydroxide. coated
ubeslos for ab.orption of CO.. 8 to 20 mesh
3.2 Sample Reco'"ery and Ana/}'sls. The
reagen t. needed for .ample recavery and
analysi. are the .ame 81 for Method a.
SectIons 3.2 and 3.3. reapectively.
4. Pmcedure
4.1 Samplmg
4,1.1 Preparation o{ Col/ection Train
Mea.ure 15 ml of 3 percent hydrogen
pero~lde into each of the first two midset
lmplngers. Into the midset bubbler. place
about 25 g of drlerite. Clean the outside. 01
the Implngera and the drierite bubbler and
weigh (al room temperature. - 20' C) to the
nearest 0.1 g. W~igh the three vessels
.imul!aneou.ly and record thi. initial mus
Place. .mall amount of 81us wool in the
Erlenmeyer bubbler. The glass wool .bould
rover the entire bottom of the flask and be
aboul1-em thick. Place about 100 g of
ucan:e on top of the glasa wool and
car.rully insert the bubbler top. Plug the
bubbler exhaust leg and invert the bubbler to
reman any ascante fom the bubbler tube. A
wlte may be u.eful In asaunng that no
Blcante remain. in the tube. With the plug
removed and the outside of the bubbler
cleaned. weigh (at room temperature (at room
trmpe'ature. - 20" C). to the neare.t 0.1 g
Record thi. initial masa.
Assemble the tram 81 .hown in Figure 81'.-
1. AdJusI the probe heater to a temperature
.u!f,uent to prevent water condensation
Place crushed ice and water around the
implngerl and bubblera.
Note.-For .tack g81 .tream. with high
particulate loadings. an in-stack or beated
out.ol-slack 8181s fiber mat filter may be u.ed
In place of the glu. wool plug in the probe
4 1.2 Leak-Check Procedure and Sample
CollectIon. Tbe leak-check procedure and
.ample collechon procedure are the .ame al
.peclfied in Method 6, Section. 4 1.2 and
4.1.3. respectively.
4 2 Sample Recovery.
4.21 Moi.ture Measurement. Disconneci
the peroxide impingera and the drierile
bubbler from the sample train. Allow time
(about 10 minutes) for them to reach room
temperature. clean the out.ide. and then
weigh them .imul!aneously in the same
manner as in Section 4.1.1. Record this final
ml:i9S
4.22 Peraxide Solution. Pour the contents
of the midset impingera into a leak.free
polyethylene botlle for .hipping- Rinse the
two "'idget impingera and connecting tubes
with delOni%ed di.hlled water. and add the
washings to the .ame .torage container.
.Mt' "~JOQ of tr.de name. or Ipeci6c productJ
do.. n .. ooNlbtule endon.menl by the U S
EnvU'o ,ental Protection AleDey,
4.2 3 CO. Al¥aroer. Allow the Erlenmeyer
bubbler to wanD to room temperature (about
10 minute.). clean the out.ide. and wei8h to
the neareat 0.1 8 in the ..me manner 81 in
Section 4.1.L Record thi. nnal ma.. and
discard the \l8ed a.carlte.
4.3 Sample Analy.i.. The .ample analy.i.
procedure for SO. i. the aame 88 apecified in
Method 8, Section U.
5. Calibration
The cali!lrationa and check. are the .ame
a8 required in Metbod 8. Section 5.
e. Calculalion.
Carry out calculatinn.. retaining at le88t 1
extra decimal fagure \>e)'ond that of the
acqwred data. Round off figures after flDal
calculahon. The calculation nomenclature
and procedure are the .ame 88 specified .in
Method e with the addition of the followln':
8.1 Nomenclatura.
c.,.o-Concentration of moiature. percenL
colA -ConceltratiOil of CO.. dry basia.
percent.
m.. = Initial mass of permdde impinaera and
drierite bubbler. 8.
m",=Final ma.. of peroxide impinaera and
drierita bubbler.I'
m.. = Initial maaa of a_rite bubbler. 8.
1IIot= Final mas. of a.carite bubbler, g.
Vcoll...., = Standard equivalent volume of
CO. collected. dry ba.i.. mI.
8.2 Co. volume collected. corrected to
.tandard condition..
Vcow .....=5.467XO-.(m.,-m.) (Eq 81'.-1)
8.3 Moisture volume collected. corrected
to .tandard conditiona.
Vw(Std) . 1.336 X 10-3 (~ - ~i)
6.4
S02 concentration.
(Eq. 6A-Z)
Cso
2
v
(V - V ) N( s01n)
t tb ~
. 32.03 a
Vm(std} + VCOZ(std)
(Eq. 6A-3)
6.5
C02 concentration.
Ceo.
2
Veoz (steS)
V.(steS) + Ve02(std)
X 100
(Eq. 6A-4)
6.6
Moisture concentration.
eH20 . V.(steS)
YHZO(std)
+ VHZO(std) + YC02(steS)
(Eq. 6A-5)
7. EmIssion Rote Procedure
If the only emillion me88urement desired
i. in terms 01 emission rate of SO. (ngl/l. an
abbreviated procedure may be u.ed. The
differences between Method 81'. and the
abbreviated procedure are de.cribed below.
7.1 Sample Troin. The sample train i. the
.ame 88 .bOWD in Figure SA-t and a.
228
de.cribed in Section 4. except that the dry
gu meter i. not needed.
7.2 Preparation of the eol/eel/on train.
Follow the eame procedure a. in Section
4.1.1. except that the peroxide impilllera and
drlerite bubbler need not be weighed before
or after the te.t run.
7.3 Sampling. Operate the train 88
de.cribed in Section 4.t.3. except that dry g88
-------
Federal Register I Vol. 46. No. 16 I Monday, January 26, 1981 I Proposed Rules
8357
meter readir.gs. barometric prenure, and dry
8as meter temperatures need not be recorded.
7.4 Sample Recovery. Follow the
procedure in Section 4.2, except that the
peroxide Impingers and drie:ite bubbler need
not be weighed.
7.5 Sample Analysis. Analysis of the
peroxide solution Is the 88me as described in
Section 4.3.
7.8 CalculatioDl.
7.8.1 so. mass collected.
v
-S02 . 32.03 (Vt - Vtb) H( ::In)
Where:
(Eq. 6A-7)
lIIso . Mass of S02 collected, mg.
2
7.6.2
Sulfur dioxide emission rate.
Eso . Fc (1.829 x
2
Where:
EooII=Emission rate of SO.. ng/I.
F.=Carbon F factor for the fuel burned.
m'/I. from Method 19.
8. Bibliography
8.1 Same as for Method 8, cilations1
through 8. with the addition of the following:
8.2 Stanley, Jon and P.R. Westlin. An
Alternate Method for Stack Gas Moisture
Determination. Source Evaluation Society
Newsletter. Volume 3. Number 4. November
1978.
8.3 Whittle. Richard N. and P.R. Westlin.
AIr Pollution Test Report: Development and
Evaluation of an Intermittent Integrated
SO./CO. Emission Sampling Procedure.
Environmental Protection Agency.
Emission Standard and Engineering
Division. Emission Measurement
Branch. Rescarch Triangle Park. North
Carolina. December 1979. 14 pages.
IllSO
109) 2
(Illaf - lIIai)
(Eq. 6A-8)
Method 6B-Detenninotion of Sulfur Dioxide
and Carbon Dioxide Doily Average
Emissions Fram Fossil Fuel Combustion
Saurces
1. Applicability and Principle
1.1 Applicability. This method applies to
the determination of sulfur dioxide (SO.)
emissions form combustion sources in tenns
of concentration (mg/M') and emission rate
(ngln. and for the determination of carbon
dioxide (CO.) concentration (percent) on a
daily (24 hours) basis.
The minimum detectable limit, upper limit.
and the interferences for SO. measurements
are the same as for Method 8. For a 2G-liter
sample. the method has a precision of 0.5
percent CO. for concentrations between 2.5
and 25 percent CO..
1.2 Principle. A gas sample II extracted
from the sampling point in the stack
Intermittently over a Z4-hour or other
specified lime period. Sampling may also be
conducted continuously if the apparatus and
229
procedure are modified (see the note in
Section 4.1.1). The so. and CO. are separated
and collected in the sampling train. The SO.
fraction Is measured by the barium-thorin
titration method and Co. Is determined
gravimetrically.
2. Apparatus
The equipment required for this method is
the 6ame as specified for Method 6A. Secllon
2. with the addition of an industrial timer-
switch designed to operate in the "on"
position from 3 to 5 continuous minutes and
"off" the remaining period over a repealing.
2-hour cycle.
. 3. Reagents
All reagents for sampling and analysis are
the same as described in Method 8A. Section
3.
4. Procedure
U Sampling .
4.1.1 Preparation of Collection Train.
Preparation of the sample train is the same 88
described in Method 8A. Section U.t with
the addition of the following:
Assemble the train 8S .bOWD in Figure 8B-
1. The probe must be heated to a temperature
sufficient 10 prevent waler condensation and
musl include a filler (either in-etack. out-of.
.tack, or both) to prevent particulate
entrainment in the perioxide impingers. The
electric supply for the probe heat should be
continuous and separate from the timed
operation of the sample pump.
Adjust the timer-switch to operate in the
"on" position form 2 to 4 minutes on a 2.hour
repealing cycle. Other limer sequences may
be used provided there are at least 12 equal.
evenly spaced periods of operation over 24
hours and the total sample volume is
between 20 and 40 Uters for the amounts of
.ampling reagents prescribed in this method.
Add cold water to the tank until the
Impingers and bubblers are covered at least
two-thirds of their length. The impingers and
bubbler tank must be covered and protected
from intense heat and direct sunlight. U
freezing conditions exist. the impinger
.olution and the water bath must be
protected.
IIlL- cOO( .-
-------
PROBE IENO PACKEDlYSTACK WALL
WITH QUARTZ OR
PYREX WOOl'
N)
(.10
o
-LING COOl ....,.c
THERMOMETFR
MIDGET BUBBLERS
"
ICE lATH
Figure 68-1. Sempling train.
NEEDLE VALVE
SURGE TANK
II
i
!.
:III
~.
l-
II
..
-
~
$
~
...
.
-
I:
8
e-
':<
.'i'
CI
i
.;!
I'
!
-
i
J
-------
Federal Register I Vol. 46, No. 18 I Monday, January 26. 1981 I Proposed Rules
8359
Note.-Sampling mey be conducled
continuously if a low flow-rale sample pump
(> Z4ml/min) is used. Then Ihe limer-swilch
is not necessary. In addition. if the sample
pump is designed for conslanl rate aampling.
the rale meler may be deleled. The lolal gas
volume collected should be between 20 and
40 liters for Ihe amounts of sampling reagenl8
prescribed ir: Ihis method.
4.1.2 Leak-Check Procedure. The leak-
chee\. procedure is the same as descr:bedf in
Method 6. Section 4.1.2.
4.1.3 Sample Collection. Record Ihe initial
dry gas meter reading. To begin sampling,
position the tip of the probe al the sampling
point. connect Ihe probe 10 the firsl impinger
(or fIlter). and slart the timer and the sample
pump. Adjusllhe sample flow 10 e constanl
rate of approximalely 1.0 liler/min as
indicated by the rotameter. Assure that the
timer is operating as inlended. i.e., in Ihe "on"
pOSitIon 3 105 minutes al 2.hour intervals. or
other time inler\'a] s;>cdfJed.
During the 24-hour sampling period. record
the dry gos meler lemperature belween 9;00
a.m. ad 11;00 a.m.. and the barometric
pressure.
At Ihe conclusion of the run. turn off Ihe
timer and Ihe samp1e pump, remove Ihe probe
from the stack, and record the final gas meter
volume reading. Conduci a leak check as
described in Section 4.1.2. If a leak is found.
void Ihe Icsl run or use procedures
accepla:,le 10 the Administrator to adjust Ihe
s(lmplc \'o;ume for leakage. Repeatlhe steps
In Ihis Scction (4.1.3) for successive runs.
4.2 S,;mple Recai'ery. The proccrlures for
sample recovery (moisture measurcm..nl.
peroxide solution, and ascarile buLbler) are
the same as in Melhod 6A, Section 4.2.
4.3 Sample Analysis. Analysis of lhe
peroxide impinger solutions is the same as in
Melhod 6, Section 4.3.
5. Calibral ion
5.1 Metering System.
5.1.1 lnitwl Calibration. The initial
calibration for the volume metering syslem is
Ihe same as for Method 6, Section 5.1.1.
5.1.2 Periodic CaliLra:ion Check. Afler 30
days of operation of the lesl train conducl a
calibration check as in Section 5.1.1 above.
except for the following variations; (1) The
leak check is nol be conducted. (2) three or
more revolutions of the dry gas meler may be
used, and (3) only Iwo independenl runs need
be made. If the calibration faclor does nol
deviale by more than 5 percenl from the
initial calibration factor delermined in
Section 5.1.1. then the dry g88 meter volumes
obtained during the lest series are acceplable
and use of Ihe train can continue. If lhe
calibration faclor deviales by more Ihan 5
percent recalibrale the melering syslem as in
Section 5.1.1; and for the calculations for the
preceding 30 days of dala. use the calibration
factor (inilial or recalibration) thai yields the
lower gas volume for each test NO. Use the
latest calibration factor for succeeding tests.
&.2 Thermometers. Calibrate againll
mercury-in-glass thermomelers initially and
al 3O-day inlervals.
5.3 Rotameter. The rolameler need nol be
calibrated. bul should be cleaned and
mainlained according 10 the manufacturer's
inslnlction.
5.4 Barometer. Calibnlte againsl a
mercury barometer initially and al 3O-
-------
8360
Federal Register I Vol. 46. No. 16 I Monday, January 26. 1981 I Proposed Rules
'.1.3 Path CEMS. It .. luaelted thlt the
effective meaaurement path (1) be totally
within the Inner area bounded by ellne 1.0
meter from the Itack or duet wall, or (2) heve
et lealt 70 percent of the path within the
Inner 50 percent of the ltack or duct crol..
eectional area, or (3) be centrally located
over any part of the centroidal area.
,,2 RM Mea.urement Location and
Trave1'8e Point.. Select an RM meaaurement
point that il accellible end at lealt two
equJvalent wametere downstream from the
nearelt control device or other point at which
a change in the pollutant concentration or
eminion rate may occur and at leut I half
equJvalent diameter upstream from the
effluent exhault. The a:MS and RM
loca tionl need not be the I8me.
Then ..leet traverse pointl Ihat aSlure
acquJ.ition of representative lamples over
the ltack or duct croll lection. The minimum
requJremenl8 are al follow.: Establish a
"mea.urement line" that palSee through the
centroidal area. If this line Interfere. with the
CEMS meuurementl, di.place the line up to
30 em (or 5 percenl of the equivalent diameter
of the croll lection. whichever ie lell) from
the centroidl\l area. Locete three traverse
poinl8 al 18.7, 50.0, end 83.3 percent of the
meuurement line. If the meaaurement line il
10lller than 2.4 metere. the three traverse
poin!1 may be located on the line at 0.4, 1.2,
and 2.0 metei"l from the Itack or duct wall.
The teeter mlY lelect other traverse poinl8.
provided that they can be IhOWD to the
lalisflchon of the Administrator to provide a
representative lample over the Itack or duet
croll lection. Conduct all necessary RM teel8
within 3 em (but no lell than 3 em from the
ltack or duct wall) of the travene pointa.
4. PerforrnanOt! and Equipment
Specification.
U Inst11J/Tlent Zero and Span. The CEMS
recorder Ipan must be let at 110 to 100 percent
of recorder fulI'lcale UIIing a Ipan level of 110
to 100 percent of the Ipan value (the
Administrator may approve other Ipan
levels). The a:MS delign mUllt allo allow tha
determination of calibration drift at the zero
and Ipan level polnl8 on the calibration
curve. If thie .. not posllble or II impractical
the delign malt allow thele determinetiODl
to be conducted at a low-level (0 to 50
percent of Ipan value) point and at a blah-
level (80 to 100 percent of Ip8D value) poInL
In Ipecial call" If not already approved, the
AdminUtrator may approve a linaIe-point
celibretion-drift determination.
U Calibration Dfi/L The CEMS
callbrltion mUllt not drift or deviate from the
refennce value of the pi cylinder, sal cell.
or O! caI ftlter by more than 2.5 percent of
the I ,n value. If the CEMS lnc1udee
poilu "It and diluent monltore, the
celibn ion drift mUIII be determlDed
leparl \ely for each In terma of concentre.tloDl
(lee PerformanCl SpecIfIcation a for the
diluent apeciflcatioDl).
U CEMS &lative Accuracy. The RA of
the CEMS mUllt be DO sreater than 210 perceIIt
of the me8J1 value of the RM telt date In
lema of the onIta of the eml8alon ltandud or
10 percent of the appUceble It.andard.
whichever .. sreeter.
5. PwfDnll- Specificatioll Telt
Prr1cedurw
U Prete.t Preparatkm. Inltall the CEMS
end prepare the RM tell lite eccordins to the
lpeciflcetionl In Section 3, end prepare the
CEMS for operation accordlna to the
manufacturer'l written inltruCtiODl.
5.2 Calibration Drift Test Period. While
the affected facility il operating at more than
50 percent capacity, or al lpecified in an
applicable subpart. determine the magnitude
of the calibration drift (CD) once each day (at
:u-hour Intervall) for" consecutive days
according to the procedure liven in Section 8.
To meet the requJrement of Section 4.2, none
of the CD's mUlt exceed the lpecification,
1i.3 . RA Test Period. Only after the CEMS
passel the CD test. conduct the RA telt
according to the procedure liven in Section .,
while the affected facility il operating at
more than 50 percenl capacity, or al lpecifiect
In an applicable lubpart. To meet tb.e
.pecificatlonl, the RA must be equal to or
less than 210 percent or 10 percent of the
applicable standard. whichever I. greater.
For iDltrumenta that use common
componenta to mealure more than one
emuent saa conltituent, all channels must
limulteneoully pall the RA requiremenL
unlesl it can be demonltrated that any
adjultments made to one channel did not
effect the othere.
8. CEMS Calibration Drift Test Procedure
The CD meuurement .. to verify the ability
of the CEMS to conform to the eltablished
CEMS celibration uled for determining the
.mlilion concentration or emillion rate.
Therefore, If periodic automatic or manual
adjustmentl are made to the CEMS zero andl
or calibration IIttingl, conduet the CD telt
immediately before the.. adjultmentl.
Conduct the CD telt at the two polntl
epecified In Section U. Introduce to the
CEMS the referenCt! saaes. sal celli, or
optical ftltere (thele need not be certified).
Record the CEMS relponee and lubtreet thil
value from the reference value (lee example
date Iheet In Fipre ~1).
If an Increment addition procedure II used
to celibrete the CEMS. a IiD8le-polnt CD telt
may be ueed al follow" Ule an increment
cell or calibration sal Ith a value that will
provide a total CEMS relponee (i.e., .taek
plul cell concentratioDl) between 80 end 95
percent of the apen value. Camp- the
difference between the me..ured CEMS
responle and the expected CEMS relpoDle
with the Incnnnent value to 88tabliah the CD.
~~--
232
-------
Federal Register I Vo1. 46. No. 16 f Monday, January 26, 1961 I Proposed RoJet
8361
Date and Calibration Monitor
Day time value value Difference
...
GJ
>
GJ
...
I
~
C
.....
-
GJ
>
GJ
...
I
.s::.
CI
....
:c
Fi gure 2-1.
Calibration drift determination.
BluING COO( lHO-26-<:
233
-------
83~
Feder8l Regiltin' I Vol. 46, No. 16 I Monday. January 26. 1981 I Propoled Rule.
8363
&100.. Aor:tIUOC'f T.., ~
".1 Somplifll Stro!lO fo, RM Tnt:J.
Cd the RM le,tl Ilich tII.1 they will
yield _clta repre,eoUltiye of tile em:...ioD8
from the IOW'U and c.&JI be co I'T't I. led 10 the
CEMS cUll. Althouah II !a preferable 10
eutlducl !he chlileol [il8JlPUcable). moi.h1r8
II! De~ed). and poUutaDl meuuremeota
.icullaDtOully. the chlilenland mouturw
lZlealurelllenta th., .re Iu.en W1thiD . » 10
tll).mlnule period. wlUch iDcllld.. the
poIJut&D1 mea,uremeDt&. -y be ....d 10
calcuI.t. dry poUulaDt CDllC&lltntion aDd
emia.ioa I"8le.
ID order 10 CGl'T'tlal8 the CEMS aDd RM
c!aa propl!riy, m.rk the be~ aDd ead of
..ch RM I... pcnod or each NIl linclllcilil8
the uact lime or'th, day) OD the CEMS chart
t'l!'C4rdinp or otller permaneal recard of
""!pilL U.. tb. roUowiDa .tnletle. for the
RM Inta:
",1.1 For iDt.esnled lampl... e... Method
e and Method t. mu.. _pl. tn.e,.. of.1
Ie..t Z1 DUDuLea. -p!iq for 7 aWlllln.1
..ch tn.e,.. poIDL
".1': For lI'ab wmpl.I.."" Metllod,..
UIr.. 008 NIIIpl. .1 each tr...,.. point.
KhedulU1a the lI'ab _pl.. 10 tII.1 tIIey en
IU.I!D .lIDulWleou,ly IwithiD . 3-aWlllle
period) or are AD eqUAl inl.rval of lima .pu1
oyer I Z1-lIIiAlIl8lor Ie.., period.
Nala-AltiID.... CEMS RA I.e." 8ft
cooduded durina NSPS perrarmADCoI ...1a.1D
6... caMS, RM ruulll oblaiD.d dllriDB
CF.MS IlA lei" ma, be lIIed 10 d.lermi.a.
aompli- u Ions a. the 1Oun:.8 ADd le.'
8D~1i0lll are _!al.enl with tII. applicabla
regu1atioD8.
7.2 Corre/oliOll of RM and CJ:MS DatA.
Cam!lale tha CEMS ADd the RM lilt da.. aa
ID dw tiID. and duration by linl d.'ermiDiDI
from the CE.\CS 6naI Oillpulith. ODe UHd for
nportiQaJ the iDlesnl.d Ivef8(le poUlitanl
amcealnlioa or lI:union rale for each
po:Jlltanl RM ..., period. Con.ider I)'III!III
.upon» 1iIDI. II imporWIt. ADd CODfina that
die pair of multa are on . consillenl
JIIoillwl.lalllpef8turw. and diJllnil
amc.all'8lio11 beaU. Thm. DlllllJIU'I eacIa
1D1~t.ed CD.cs Valli. a"aIo8t the
IXIl'T'tlpoDdiq ..erqe RM nJue. U.. tIIa
foUowiDa ,wdelion 10 IIIab thaae
IXImparilOos.
7.z.1 Utile RM II.. an tol~lad -p\ioa
IKhniqlle. make I ~ comparilOn of the
RM reNII and CD.cs inlllflt.ed 'Yef8(le
...1:1..
7.u U the RM Iw I I/'Ib -p\ioa
..cllDiqll8, lint av.r.,. t.ba I'8lllltalnnD all
I/'Ib -,Iaa takn duriq tII. IeIt run and
than CII8Ip8I'8 tbia ave,.,. yalile "liIIal \be
IDt~tad yalue ob~ &om the CEMS
cb.:'! reconIiq dlll'iD8 the nuL
7.s NUlllbe, t1f RM T..,.. Conduct I
IlliAimWII of aID.e .... of aII-,aary RM
...,.. For I/'Ib -pia.. ..... M.tllod 7.. ..,
18 m.'" up oI.t I.ut thne ..p...ale
mea.1lftJD8D1a. Conduct ..ch ..I witJ1io .
period 0131110 eo IlLi8uta..
Nota.-11I. ...,. ma, ~ to perlo""
mort thu aID.e 8111 01 RM lei... U tbia option
Ie choMA. the ""Ier may. .. Ilia d'lCI'Itioll,
nfect .ID8XimWII of three ..II of the te.t
naulll 10 Ioaa a. the IDtaI aWllbar of ....
...ullI uad 10 delenahle tII. rellliY,
.ccuracy ia I/'I,'er thu or eqUAl to aID.e. but
lie mut report all dallllDdudioa the rejected
cia...
7.. 1IIt-- M.th0d8. UoJe. otllerwi..
apecifiad iD an .pplica bla IIIbpart of the
regulalioD8. M.tllodl a. 7. So and t. or tIIeir
.pproved allemaliy... are the f8fereoce
m.thod. for so.. NO. dillIenllo. or W.).
tnd moi.lar8. rtlpeCliY.I)'.
7.5 Coleulotio,... Summarial tII. mullI
va . dlla .beet AD ex.mpl. ia abawo in
I'I8an s-2. Calculate the 81180 of the RM
...lu." Calculale tII. arithmetic differeDC81
betwen the R,\( and tile CEMS output 8It&.
502 NO b . 50 a NO .
II C02 or 02 2 II
IU1 .. ID1ff RIoI. 1'1 lUlU IU1 I~ M --.rM- Tlr I D1 H RPiI II I D1ff
:~" Date .nd DDlIIC ,d ,d
o. time n....c
1
2
3
4
b
fi
7
8
9
10
11
-
.
-
Avt!ra(~
~t!nce Interv.l - -
"ccur.cve I I
a . D
Average of threl samples; C Hake sure that AM .nd H data Ire on I conststent basfs,
either wet or dry.
Ftgure 2-2. Relltive .ccurlcy determfnatfon.
for steam generators.
8IUJIIQ C'ODI -.......e
234
-------
8362
Federal Register I Vol. 46. No. 16 I Monday. January 26. 1981 I Propos!!d Rul!!s
8364
Then calculi Ie the mean of the diHereDce.
ltandanl dmatioD, confideDC8 CDeffic.ienl,
and CEMS RA. uaina EqDetionl z..1. z..2. z-.3.
and z-4.
& Equatjall6
8.1 AritJunetjc Mean. Calculate the
utthmelic mean of !be diBereJlC8, d. of a data
leI u followa:
1
if - -
n
n
t
t-l
dt
:ihere:
n
- Nuaber of data potnts.
n
! dt
t-l
Wbeu the IDeIUl of the difl'emsce. of pain
of data fa calculated. be lure to CfI1T8CI the
data for mobhlre, If applicabla.
(Eq. Z-1)
- Algebraic SUI of the tndividual differences, dt.
I8.UIG cow -
B.2 StaJ1darrJ INvio/ion. CalcWlle the
ltandanl dena tioo S. U fDUow5:
(; .l
.!:L-
([q. 2-2)
,,-I
8.3 Confidence Coeffici.:nf. Calcullte the
%.5 percenl error cDnfideoC8 ooeffu:ieot (ooe-
tailed) CC at foUDw.:
Ct . fo.975 ~
...
(Eq. 2-3)
Where:
'D.97S-I-valul!8 (see Table z..1)
Table 2-1. '"VALUES
~ ~ .. ....,. ... ....,.
. 12.701 7 1..44' 12 ~,
.. 4.3Oa a ~ 10 I.''''
. 1.'82 . :t3)II U 1."'0
1 1.711 10 2.262 15 I."5
. 2.511 'I 2.Z2a ,. 2.'31
.1100 ..!ow .. .... ..bIo on "'""'" ..........t "" ...1
..,... 01 fNodaa Uoo . ...-lID tJw - .. ..........
IIInJ-
8.4 Relative A=cy. CalcuJlte the RA
of I .et Df dlta II fDUDw5:
RA ..lll..:!:J.f£l X 1 00
m
Where:
lal
(Eq. 2-4)
. Absolute value of the mean of differences
Ice I
(from Equation 2-1).
. Absolute ~alue of the confidence coefficient
RH
(from Equation 2-3).
. Average RM value or applicable standard.
235
&RaportiJtg
AI 3 minimum (check with the I ppl"Dptia te
regi01lal Dffice. or State or local agency fOT
additiooal ~uirementa, If any) .ummarize In
tabular form the caLbratioo drift leal. and
the IlA le513. Ioclude all dall ob~ta,
calculltioos, and chartJI (reconl of dala
oUlpu..) thai are oece5.ary to .ub.ta.otlllte
that the performance CEMS mel the
performance speo.fic.a liDO.
10. Bibliography
10.1 "Experimental Suti.tic.a."
Departmenl of Cammel'Cl!. Handbook 111,
1963, pp. Wl, paregrapu 3-3.1.4.
Performancr S~fiCDuan 3-SfJ«ifiCDtiaN
and Te,t Proc~ure' for 0, and Co.
Can/inuau. Emiuion ManiloriDg Sy-62UW in
SID/iDDQry Sowr.a
L Applicability and PrincipltJ
1.1 App!JCDhility. 'J'ha 8peciJic.aboo ;. to
be uaed for evaluabna the .a:eptab,Lty of 0.
and CO. c;ontinuo\U e.mi..ioo mOr.J10f1D.8
ry.tem.s (CEMS) after initial wtallat>on and
wheoever .~ed in &lI .ppuc.able Rbpar1
of the ~at>OIl8. Tba .peafic.atioo .ppue.
to O. and co. moruto... th.t ~ 001 Ulduded
under Perlormanc.a Speci.6c.atloo 2.
The defiwbata, inJotallatioo meuuremeot
Iocauoo .peclic.aUOIa, te.. pl"OCedure.. data
",duction procedure.. "'portulg n>quiremen~.
&lid bibliography ~ the oame .. U1
Puform.oce S~c.atlOD 2. SeCtlolU 2. 3, 5-
e. 6. 9. &lid 10. and .wo apply 10 0. aDd CO.
CEMS UDder !hi. .peci.6c.a tloa. 10 e
performance and equipmenl .peci.6c.abolU
&lid the relative accuncy (RA) t..1
procedures for O. and Co. CEMS chifer &-om
SO, and NO. CEMS, unleu Oth81"W'\M DOled.
aDd IU"8 theref..... Incloded h......
1.2 Principle. Refe",oCl method (R\{)
1f:au and cahb..tioo drifHe.1I ~ c:ond~cled
10 d elermine canformUIQI of the CEMS WI th
the .peci.6c.aboo.
1. Performancr and Eqaipmenl
5p«;r/lcauaN
%.1 wtrumtJn/ ZBm and Span. Th.
8peciJic.atioo ia the .8IOe u Secl100 U Df
Performan c.a Specif\c.a bOO 2.
2..2 CalJbmtian Drift. 11Ie CEMS
oahb..tioo mu.sl Dol dnft by DIO", than 0.5
perceot 0. or CO. &-olD the refe~a value or
the 8". g.. cell or optical filler.
%.:! CEMS Relalin ACCU/'Clcy. 11>e RA of
the GEMS mu.st be DO gre.ter than 2D perceot
of Ibe mean value of the RM I.e.t dill or 1.0
perceot 0. or co.. whichevPl' ia gre.ler.
L Relati". A=uucy Tul ProcadUIfJ
1.1 Sampling Strali!SY for RM T~ts.
correlotion of RM aJ1d CEMS dolo. Number
of R.'J Tesu. and Calcu1atJaN. ThIs It the
lame .. Performanc.a SpecIic.atloo 2.
Secbo05 7.1. 7.2. 7.3. aod 7.5, relpectJvety.
1.2 Referencr Ml!Lhod. Vole.. othe.rwua
8peClfied in .0 appuc.able .ubper1 of lb.
reguI.tiO!l5. Method 3 Df Appeod1X A or any
Ipproved alternative ia th. manila _lbad
for 0. or CO.:
(See. 114. Oean Alz Act. II am8llded [U
U.s.c. 7414))
(PIt Do<. n...-. I'!I8II..-a1: - -I
~~-
-------
Federal Register I Vol. 46. No. 138 I Monday. July 20. 1981 I Proposed Rules
37287
ENVIRONMENTAL PROTECTION
AGENCY
.0 CFA Part 60
[AD-f'RL 1715-YI
Stand8rds of Performance for N..
Stationary Sourcn: Continuous
Monitoring Performance
Speclflcatlonl; Proposed Revisions to
Gen."" Provision.
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule and notice of
public hearing. .
SUMMARY: On February 23. 1978 (43 Fa
7568) the Environmental Prorection
Agency promulgated standards of
performance for new or modified kraft
pulp mills pursuant to Section 111 of the
Clean Air AI!! as amended. The
standards require a continuous emission
monitoring system (CID.IS] to monitor
total reduced sulfur (TRS) for operation
and maintenance purposes. However. at
the time the standards were
promulgated performance specifications
for the monitors had not been completed
and monitoriD8 requirements were not
to be effective until their completion.
The specifications proposed herein
complete the performance
specifications. In additlOl1. changes to
the general monitoring requirements of
Section 60.13 are proposed.
A public hearing Will be held. if
requested. to provide interested persons
an opportunity for oral presentation of
data. views or argumenta concerning the
proposed performance specification and
changes to Section 60.13.
DATES:
Comments. Comments must be received
on or before September 18. 1981.
Publjc Hearing. If requested. a public
hearing will be held. Persons wishing
to present oral testimony must contact
EPA by August 10. 1981. lfa hearing is
requested. an announcement of the
date and place will appear in a
separate Federal Register notice.
ADDRESS:
Comments. Comments should be
- submitted (in duplicate if possible' to:
Central Docket Section (A-130).
Attention: Docket Numuer A~57.
U.S. Environmental Protection
Agency. 401 M Street S.W..
Washington. D.C. 20460.
Public Hearing. Persons wishing to
present oral testimony should notify
Mrs. Naomi Durkee. Office of the
Director. EmissIOn Standards and
Engmeering Division (MD-13). U.S.
Environmental Protection Agency.
236
-------
37288
Federal Register I Vol. 46, No, 138 I Monday. July 20. 1981 I Proposed Rules
Research Triangle Park. North
Carolina 27711. telephone number
(919) 541-5571.
Docket. Docket No. A-8(}-57. containing
material relevant to this rulemaking. is
available for public inspection and
copying between 8;00 a.m. and 4;00
p.m.. Monday through Friday. at EPA's
Central Docket Section. West Tower
Lobby. Gallery 1. Waterside Mall. 401
M Street. S.W.. Washington. D.C.
20460. A reasonable fee may be
charged for copying.
FOR FURTHER INFORMATION CONTACT:
Mr. Roger Shigehara. Emission
Measurement Branch. Emission
Standards and Engineering Division
(MD-19), U.S. Environmental Protection
Agency. Research Triangle Park. North
Carolina 27711. telephone nwilber Icn9)
541-2237.
SUPPLEMENTARY INFORMATION: On
February 23. 1978 (43 FR 7568). the
Environmental Protection Agency
promulgated standards of performance
for new or modified kraft pulp mills
pursuant to Section 111 of the Clean Air
Act as amended. The regulation requires
new kraft pulp mills to demonstrate
compliance with the standards of
performance by means of performance
tests at the time the new source
commences operation or shortly
thereafter. To insure that these sources.
including associated air pollution
control equipment. would be properly
operated and maintained (to insure-the
intent of the standards to reduce air
pollution), provisions were included that
require sl!Veral monitoring systems to
continuously monitor emission levers.
One of those monitoring system.s was
for total reduced sulfur (TRS).
At the time the standards. which.
included these monitoring requirements.
were initially proposed. EPA and the
kraft pulp mill industry were engaged in
developing performance specifications
for TRS monitoring systems. The
performance specifications were not
completed by the time the standards of
performance were promulgated;
therefore, the monitoring requirements
were not to be effective until a joint
EPA-industry effort to develop
performance specifications was
completed.
In October of 1977. the National
Council of the Pulp and Paper Industry
for Air and Stream Improvement
submitted a technical assessment study
to EPA. The results of a month-long
evaluation of the performance of
existing TRS monitors and a comparison
with Method 16 data were included in
this study. This study serves as the
technical background for the
performance specification proposed
today.
The specifica tion requires that
monitors used to measure TRS be
Installed and ensured to operate
properly. Calibration drift and relative
accuracy tests are to be conducted to
determine conformance of the
continuous emission monitoring systems
(CEMS) with the specification.
Candidate monitors include the
coulometric titrator. flame photometric
and photoionization detectors. and
others, fitted with appropriate sample
extraction and conditioning equipment.
A document has been prepared to
provide vendors and operators with
guidelines for performance and
equipment specifications and suggested
test and data reduction procedures for
evaluating the CEMS. This guideline
document is available from Mr. Foston
Curtis. Mail Drop 19. Environmental
Protection Agency, Research Triangle
Park. North Carolina 27711. (919) 541-
2237. During the development of the TRS
performance specification. a question
arose concerning the possibility that the
CEMS might be the same as Reference
Method 16. The question concerns
whether such systems should be
exempted from the relative accuracy
test because it would involve comparing
a reference method against an
automated reference method. Comments
are requested on this question.
As discussed in the preamble to the
final rule which established the
standards of performance for kraft pulp
mills (43 FR 7571). installation of
continuous monitoring systems is not
needed until promulgation of applicable
performance specifica tions. Sections
6O.13(a) of Title 40 indicates that
continuous monitoring systems must
comply with the monitoring
requirements upon promulgation unless
otherwise specified in an applicable
subpart or by the Administrator.
When Performance Specification 5 is
promulgated, the Administrator could
decide if any delay in complying with
the monitoring requirements after
promulgation is warranted for kraft pulp
mills which are already affected by the
standards. However. notice of these
requirements is being given with today's
proposal. The time between proposal
and promulgation is usually about one
year. The time before promulgation
should allow kraft pulp mills to initiate
purchasing and installig a continuous
monitoring system. A delay beyond
promulgation similar to the 180 days
allowed for performance tests (40 CFR
60.8) is considered reasonable.
However, in certain cases, additional
time may be required for kraft pulp mills
237
which are already affected by the
standards. The Administrator plans 10
specify additional delays as set forth In
40 CFR 6O.13(a) based on the expected
time a source already affected by the
standards would need to review
available monitors. to purchase a
monitor. to install the monitor. and 10
place the monitor into operation.
Comments concerning the lBO-day delay
and additional delays are specifically
requested.
The costs asociated with continuous
monitoring are difficult to asess because
costs will vary from source-to-source
depending on the vanahons in the
requirements for each installation. e.g.,
procurement, shipping, sIte preparahon.
and physical installahon of the
instrument system. However. for TRS
monitoring systems. the nonnal costs of
procurement are in the range of $15.000
to $30.000. The installation and teshng
costs required by Performance
Specification 5 are approximately $3600
(30 man-days at $15 per hour).
During prepara tion of this
performance spec1ficahon, consistency
with the existing monitoring
requirements of 40 CFR 60.13 was
checked. These existing monitoring
requirements provide a general basIs for
continuous monitonng requirements
found in standards of performance for
new sources, such as the standards for
kraft pulp mills. One minor
inconsistency was found in paragraph
8O.13(e). Because TRS was not
mentioned in this paragraph. a revisIOn
to the paragraph is being proposed 10
make the paragraph apply to TRS and
other emissions. In addition to this
minor inconsistency. several paragraphs
which are no longer applicable were
found. These paragraphs were effective
only until September 11, 1979. Therefore,
to update and reduce the complexity of
40 CFR 60.13, it is proposed that the
parts of paragraphs 8O.13(a). 6O.13(c),
and 6O.13(e) which are no longer
applicable be removed from 40 CFR
60.13.
Pursuant to the provisions of 5 u.s.e
Section 605(b). I hereby certify that the
attached rule will nol. if promulgated.
have a significant economic impact on a
substantial number of small entities.
About two-thrids of the businesses
owning kraft pulp mills are also engaged
in other activities. such as chemical
manufacture. detergent production. land
development and can production. In
addition. businesses owning kraft pulp
mills but not engaged in these activll1es
are almost always engaged in the
production of timber or paperboard.
Because most businesses owning krdfl
pulp mills are engaged in aclivllies other
-------
Federal Register / Vol. 46. No. 138 / Monday. July 20. 1981 / Proposed Rules
37289
Ihan kraft pulping. very few small
enlltles. as defined in 13 CFR Part 121.
could be impacted by this nile. Thus. the
a ttached nile wIll not. if promulgated.
have a significant economic impact on a
subslantlal number of small entities.
I ha ve reviewed this propoled nile to
determine if it is a major nile as defined
in Executive Order 12291 (46 FR 18193).
The costs of procurement and
installation. as indicated above. do not
indicate that this rule would result in an
annual effect of $100 million or more. a
major increase in costs or prices. or
other significant adverse effects. Thus. I
have determined that this rule is not a
major nile.
This regulation was submitted to the
Office of Management and Budget for
review as required by Executive Order
lU9l.
This notice of proposed rulemaking is
issued under the authority of Sections
111.114. and 301(a) of the Clean Air Act
as amended (42 U.S.C. 7411. 7414. and
7601(a)).
Dated: July 8. 1981.
Ana. M. Gonuc:b.
AdminIStrator.
It is proposed tha t 1 60.13 and
Appendix B of 40 CFR Part 60 be
amended as follows:
1. By revising 160.13(a). 6O.13(c). and
6O.13(e): by removing subparagraphs (1)
and (2) of 160.13(a): by removing
subparagraphs (1). (2). aDd (3). of
1 6O.13(c): and by removing
subparagraph (3) of 160.13(e) as
[ollows:
Subpart A-General Provisions
~ 60.13 Monitortng requirements.
(a) For the purposes of this section. all
caontmuous mOnitoring systems
required under applicable subparts shall
be subject to Ihe provisions of this
section upon promulgation of
performance specIfications for
continuous mOnitoring systems under
Appendix B to this part. unless
otherwise specified in an applicable
subpart or by the Administrator.
[c' 'uring any performance' tests
requi d under i 60.8 or within 30 days
therea er and at such other times as
md\' be required by the Administrator
under Section 114 of the Act. the owner
or operator of any affected facility shall
conduct contmuous mOnltormg system
performance evaluations and furnish the
Admmlstralor wlthm 60 days thereof
I wo or. upon request. more copies of a
written repo. t of the results of such
tests. These continuous monitoring
system performance evaluations shall
be conducted in accordance with the
requirements and procedures contained
in the applicable performance
specification of Appendix B.
(e) Except for system breakdown..
repairs. calibration cbecka. and zero and
span adjustmentl required under
paragraph (d) of thi. section. all
continuou. monitoring systems shall be
in continuou. operation and shall meet
minimunt frequency of operation
requirements al follows:
(1) All continuous monitoring sy.tem.
referenced by paragraph (c) of thi.
section for mea.uring opacitY of
emiSlions Ihall tomplete a minimunt of
one cycle of sampling and analyzing for
each successive 10-second period and
one cycle of data recording for each
succeSlive ~minute period.
(2) All continuous monitoring systelD8
referenced by paragraph (c) of thi.
section for mealuring emi..ion.. except
opacity. shall complete a minimum of
one cycle of operation (samplinl.
analyzing. and data recording) for each
successive 1S-minute period.
2. By adding Performance
Specification S to Appendix B of 40 CFR
Part 60 as follows:
Appendix B-Performance
Specification.
Perfonnaace SpecificatiOD ~pecificati0D8
and Te.t Procedwea for TRS CoDliDu0U8
Emi.IiOD Moaitorinl Sy.l.ma La S..tiDD8l)'
Soun:e.
1. ApplicabIlity and Principle
1.1 Applicability. This specification i. to
be used for evalualins the acceptability of
tolal reduced .uJfur (TRS) continuou.
emlS.,on monitoriOl sy.lems 1CEMSI after
imhal mslallation and whenever .pecified in
an applicable subpart of Ihe resulationa. The
CEMS may include O. momtora.
The defanitions. installation specifications.
lesl procedures. data reduction procedures
for delermininl cahbretion drifti and relative
accuracy. and reportiOl of PerfOrmance
Specification Z, I Section. Z, 3. 4. 5. 8. 8. and 9
also apply 10 Ihi. specification and mUlt be
consulted. The performance "nd equipment
specifications do not differ from Performance
Specification 2 except 81 lis led below and are
included in Ihis specIfication.
1.2 PrincIple. Calibration dnfl and
rela live accuracy leslS are condllcled to
I All ~(erences 10 Perfonnance Speclficallon Z
Me 10 the one proposed on January 26. 1981 148 fR
8JSZI
238
delermine conformance of the CEMS with the
speClficallan.
2. Performance and Equipment
Speclficatione
2.1 Inslrument Zero and Span. The CEMS
oe\:order span mu.t be set at 90 10 100 percenl
of recorder full-acele u.iOl a span level of 90
to 100 percent of the Ipan value (other span
levela may be Uled with th~ approval of Ihe
Admini.trator). The CEMS de8lp shall also
allow the determination of calibration al the
zero and Ipan level pointl of the calibration
curve. U thil il not potlible or il impracticaL
thele delerminations may be canducted al a
low level (up to 20 percent of span value)
point and at a hi8b level (80 to 100 percent of
Ipan value) poinL The componentl of an
acceptable permeation tube IYltem are lilted
on PRlel 87-94 of Citation 2 of the
bibliolll'aphy-
z.2 Calibration Drift. The CEMS
calibrallon mUlt Dot drift or deviate from_tha
reference value of the calibration sal by
more than 3 percent of tha eltablilhed span
value of 30 ppm. U the CEMS includel
pollutant and diluent moniton. the
calibration drift mUlt be detennined
IIparately for each In terml of concentrations
'(see Perfonnance Specificallon 3 for the
diluent lpecificallons).
2.3 CEMS Relativa Accuracy (RA). The
RA of the CEMS Ihall be no lJI'tIeter than 20
percent of the mHn value of the reference
method (RMJtelt data in lena. of the unltl of
the emi..ion ItaDderd or 10 percenl of the
applicable Itanden!. whichever il peter.
3. Re/atiVfl Accuracy Telt Procedure
3.1 Samplins Stratqy for RM Telts.
Correlation of RM and CEMS Date. Number
of RM Tesll. and Calculetion.. This i. the
lame 81 Performance Specification Z.
Section.. 7.1. 7.Z, 7.3. and 7.5. respectively.
3.2 Referenca Methods. Unle.. olherwise
specified in an applicable subpert of the
re8Ulationl. Method 16. Method t8A. or other
approved alternallve. shall be the reference
method for TRS. Note: For Method 18. a lit il
mede up of at le8lt three separale injects
equally spaced over time.
4. Bibliography
U "Experimental Slaliltics." Deparlment
of Commerce. Handbook 91. 1983 pp. 3-31.
parasrephl 3-3.1.4.
4.2 "A Guide to the Deli(ll1. Mainlenance
and Operetion of TRS Monilonns Syslems,"
Nalional Council for Air and Stream
Improvement Technical Bulletin No. 89.
Seplember 1971.
4.3 "Observation of Field Performance of
TRS Monitors on a Kraft Recovery Furnace."
National Council for Air end Siream
Improvement Technical Bulletin No. 91.
January 1978.
IFR 0... II-210M Flied 7-11-0111. ... '.1
BIWNG COOl ---
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53144
Federal Register I Vol. 46. No. 208 I Wednesday. October 28. 1981 I Rules and Regulations
40 CFR Part 60
(LCE FRL-1IZ1-1]
Alternate Method 1 to Reference
Method 9 of Appendix A-
Detennlnatlon of the Opacity of
Emission. From Stationary Source.
Remotely by Udar; Addition of
Alternate Method
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Fins] ruJe.
SUMMARY: EPA is amending its
regulations to establish an AJtemate
Method 1 to Reference Method 9 of
Appendix A of 40 CFR Part 60. This
alternate method employs a lidar (laser
radar) for the nonsubjective
determination of the opacity of visible
emissioDi &om stationary sources. ]I
will be used during nlahttime hours as It
Is during the day. The use of Reference
Method 9 is restricted to dayli&bt.
The effect of thil rulemaking II to
allow EPA. state and 100aJ agencies to
use AJtemate Method 1 (lidar) to
aUorce opacity standards in all cases
where Reference Mlthod 9 Is now
authorized. These cales include New
Source Performance Standards codified
in 40 CFR Part 60 and. pursuant to 40
CFR 52.12(c)(I). opacity standards in
State Implementation Plans (SIPs) that
do not speCify any test procedure.
EFFECT1VE DATE: October 28. 1981.
FOR FURTHER INFORMATION CONTACT:
Arthur W. Dybdabl. Nations]
Enforcement Investigations Center. U.s.
Environmental Protection Agency. P.O.
Box 25227. Denver. Colorado 80225, (303)
234-4658. FTS 234-4658.
SUPPLEMENTARY INFORMATION:
Introduction
Lidar. an acronym for Light Detection
and Ranging. was first applied to
meteorological monitoring in 1963. Since
that time lidar has been develo~d 88 a
measurement technique for plume
opacity. and today is approved as an
'altemate to Reference Method 9 which
employs visible emissions observers.
Lidar contains its own unique light
source (a laser transmitter which emits a
short pulse of light) which enables it to
measure the opacity of stationary source
emissions during both day- and
nighttime ambient lighting conditions.
The opticaJ receiver within the lidar
collects the laser light backscattered
(renected) from the atmospheric
aerosols before and beyond the visible
plume as well as that from the aerosols
(particulates) within the plume. The
receiver's detector converts the
backscatter optical signal into an
electronic signal. Plume opacity is
caJculated from the backscatter signal
data obtained from just before and
beyond the plume.
Background
During its development. Reference
Method 9 was found to be influenced by
the color contrast between a smoke
plume -and the background against
which the plume is viewed by visible
emissions observers. It was also
Influenced by the total ambient liJlht
(luminescence contrast) present A
plume is most visible and presents the
greatest apparent ope city when viewed
against a contrasting background (white
plume viewed against a clear blue sky).
Under conditions presenting a less
contrasting background. the apparent
opacity of a plume is lel8 and
approaches 'Zero as the color contrast ar
the ambient ligbt level decreal.. toward
zero. An exampla is viewins a white-to-
gray plume against a cloudy or huy sky.
Th. measurement of smoke plume
opaolty with the lidar Is independent of
the color cantralt conditions that exist
between a plume and the r8spectin
background (clear sky. cloudy sky.
terrain. etc.). and ambient lighting
conditions. Lidar does not consider
plume-to-b8ckground contrast in
measuring plume opacity.
On July 1. 1980. EPA proposed the
lidar technique in the Federal Register
(45 FR 44329) as AJtemate Method 110
Reference Method 9 of Appendix A.
Need for the Alternate Method
Persuasive considerations supporting
EPA development and approval of the
alternate (lidar) method include the
following:
. Independence from ambient lighting
conditions which allows opacity
measurement during day- and nighttime
hours;
. Objective measurement of a
physical property (opacity) whicb is
calibrated. and correlated with the
reference method;
. Remote operation which neither
interferes with nor disrupts the
regulated public;
. Application of statisticaJ techniques
to assure high confidence levels in the
data used for compliance determination.
Difference From Proposed Method
The approved alternate method varies
from its proposed form as published in
239
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Federal Register I Vol. 46, No, 208 I Wednesday, October 28. 1981 I Rules and Regulations
53145
the July 1, 1980 Federal Register. The
proposal was edited for clarity and
brevity. lnIormative material (examples)
and the mathematical derivations were
!!loved into the technical support
document. Reference 5.1. The fmal
regulation is approximately two thini8
of the proposal's length.
A list of definitions relatin& to lidar
technology was placed in the fint
section. The selection of pick intervals
was simplified to avoid ambiglUty. The
equation for the standard deviation was
further derived and simplified to usure
a n,gh confidence level in the data that
is used. Its definition and derivation are
contamed in the technical support
document. The opacity concept is
clearly identified and the tennl "actual
plume opacity" aDd "actual average
plume opacity" are defined using lidar
measurements. These opacities are
correlated to the reference method. A
more accurate azimuth angle correction
equation was put into the regulation for
converting the opacity valuea measured
along the laser beam's slanted pathway
through the plume to the opacity value
of the piume cross section. The running
average method was eliminated so that
it would not be confu.sed with any other
applicable staudard.
The design performance specifications
for the lidar system were generalized
and converted into affinnative'
reqwrements. This enables the
construction and use of lidar systema
with ruby or other lasers.
All recordkeeping requirementa were
changed to suggestions. EPA operators
will follow these suggestions closely but
others who design. build. or operate a
lidar system will have no recordkeeping,
reportmg. or other paperwork
obligations. This flexibility allows
consrruction of lidar systems by thOIl
persons wanting to use the alternate
method WIthout imposing any additional
regula tory burden upon the public.
Public Comments
The public comments received on the
proposed regulation were individually
exammed by the EPA workgroup. Each
comment was resolved and appropriate
chan~es appear in today's regulation.
All of these comments were generalized
into t~o major topics which are
discu .d below. These include the
a ppL' Ion of lidar technology to the
reguld I, .y process and its applicability
for mea - urmg the opacity of emissions
f~orn d spec:flc source. Several
crrn~entators exammed the available
liter31ure or recounted their own
expenences when they asked to see a
cor~pl,jtlon between the proposed
~e'hod dnd the reference method. The
:esutls of Ihls test also satisiied many of
the theoretical and philosophical
concerns. Safety concerM for the
operators and the public were
expressed. Commenta were also
received on how the system would
operate. what degree of .ubjectivity the
operators would have and the
availability of equipment or operatora.
Legal concema ware directed to an
lnIemtd regulatory change and also to
constitutional lanea. The responD to
these commentals detailed below.
Public commenta expresaed a concem
that the use of lidar for the remote
measurement of emillions opacity from
.tationary source. was a premature
application of experimental technology.
EPA evaluated two decadel of literature
describin8 the development of Udar
technology. The lilt of referenc.. in the
technical support document
demonstrates the careful ageDC1
consideration uaed to develop lidar into
an alternate method for the remote
measurement of opacity.
Several commentaton Indicated that
the data derived from the application of
the alternate method to a specific
emission IOW'C8 might be stricter than
data produced b, the reference method.
Plume characteristiCl, including particl.
size and particle color. were mentioned
as indIvtdual variables which miaht
affect the data generated by Udar. EPA
performed extensive testa to correlate
Alternate Method 1 with Reference
Method g [S81 Reference 5.1J. The data
reduction techniqua auures that lidar-
determined opacity values will not show
an emillion source exceediIJ8 an
opacity standard when the reference
method would not also show that it wa.
exceediIJ8 the standard. m some cases,
Alternate Method 1 will show a source
to be in compliance with opacity
standarda when a visual observer would
report that the source was not In
compliance with the standard.
Some of the comments were directed
toward an apparent subjectivity in the
UII of lidar when there was a potential
for external interference during an
opacity measurement EPA has shown
that lidar may be uaed to measure
opacity values Imder a wider variety of
conditions than would be possible using
the reference method. However, lidar.
determined opacity values will not be
used for enforcement purposes when
intervening variables sigtlmcan1ly
interfere with an opacity determination.
Examples of it heavy precipitation event
or excessive ambient (wind blown) dust
were gh'en 10 explain potential causes
of erratic data. These opacity values
would be excluded from an enforcement
decisIOn by the data reduction technique
which identifies and discards
unsatisfactory data.
240
All of the other limitations noted by
commentators are no more restrictive
than conditiona met during the visual
determinati.on of opacity. For example,
the proximity of other plumes was
mentioned. EPA hat shown that a lidar
is able to distinguish individual plumes
that are not In spatial coincidence. It
requirel no more than 50 meters of
clearance before and beyond the plume
along ita Une-of-sight. The positioning
problem Is far lelll'htrictive because
the lidar system only meuures the
optical backscatter produced by Its own
unique light source. Ita only position
restriction i. a 158 cone angle about the
SUD which eUminates solar signal noise
in the receiver. The initial positioning of
the Udar is approximately perpendidu.lar
to the direction of the plume. The lidar
data reduction technique compensates
for signficant plume drift and. unlike the
reference method. adjustments are made
to determine the opacity of the actual
cross section of the plume. The lidar
operetors verify that the meuurements
are taken in the same part of the plume
that visual obaerven would ~se. This,
for example, precludes misleading
mell8urementa taken if a certain plume
were to loop tightly back upon itself.
Some commentators were concerned
with the Udar's ability to determine
opacity values for a source with an
attached steam plume during nighttime
meesurements, EPA has suggested
several visual aids which are available
to verify the proper use of the lidar
during nighttime measurements. Even
without thell aide., the lidar is capable
of discerning the sudden change in
opacities which would allow the
altemate method to be used for this
purpose. The system's data display
allows the lidar operator to distinguish
the end of an attached steam plume and
consequently permits the measurement
of the residual plume opacity. It is the
characteristic of the nearly 100% opacity
and high reflectivity of a steam plume
tha t allows the lidar to make this
measurement when the other mentioned
visual aids may not provide adequate
information. Other nighttime concerns
expressed were the inability of a source
to refute lidar determinations because.
the source would be Imable to field a
team of visual observers. EPA notes that
the source is in control of the operation
and has acceS8 to monitoring and
production records which could be used
for this purpose.
Many commentators were concerned
with the possibility that thelidar-
determined opacity values for an
emission source would vary from
opacity values determined by \isual
observers. As a result of these
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53146
Federal Register I Vol. 46. No. 208 I Wednesday. October 28. 1981 I Rules and Regulations
comments, EPA conducted a
collaborative test to determine if any
discemable variance would be detected.
The result. of the test .howed that the
lidar-measured average opacity was 490
(full.cale) greater than that obtained by
the vilUal emissions observers for black
smoke. For white .moke the lidar-
measured average opacity was 8% (full
scale) lower th8D that obtained by the
observers.
EPA applied the results of the
collaborative test and the fact that lidar
is more sensitive to low-level visible'
emissions than visible emissions
observers (giving rise to the definition of
correlation which states that 0% opacity
by Reference Method 9 Is defined as
being less th8D or equal to 5% plume
opacity by lidar determination), to
define actual plume opacity. This
opacity value is calculated from the
lidar-measured opacity as shown In
Equation AMI-15 of the Altemate
Method. The reasons for, 8Dd the
derivation of this equation. is provided
In Reference 5.1 of Altemate Method 1.
Other commenta were addressed to
the correlation of the Udar system with
various operators or with other Udar
systems. Each EPA crew of lidar
operators must demonstrate their
proficiency at leut 8DDually during the
calibration tests. Other lidar systetns
must satisfy the requirements of the
Performance Evaluation Testa of the
Alternate Method. EPA sees no useful
enforcement purpose for c0l!1parlng lidar
systems with each other.
Commentators suggested that lidar
opac;lty values obtained from a small
portion of a plume would fail to account
lor the averaging effect of a visual
observer or the slower responding In-
stack transmissometer, when reading a
highly variable plume. This was not
observed during the collaborative
testing. but even if it is an Inherent
characteristic. the lidar-determined
opacity values would average out the
variation observed In time and space.
The comments directed to aspecta of
Reference Method 9 do not apply to the
Alternate Method. Such comments
included discussions of: (1) stricter
technical requirements for in-stack
transmissometers than those used for
ths Method 9 calibrating smoke
generators. and (2) the relationship
between visual opacity and mass
emissions. The use of the alternative
method does not change the basis for
the reference method. Lidar is used to
make the same determinations that
Method 9 was approved to make. The
approval of a lidar system for the
remote determination of the opacity of
stationary source emissions provides a
consistent. reliable mechanism for
extending regulatory compliance
determinations under a wider variety of
conditions. This extension clearly
furthers the objectives of the opacity
standard by verifying that stationary
source. mset opacity requirement. at all
t1m8l. day and night.
A frequent comment was addre88ed to
the safe use of a Udar system In the field
environment. Concems were expre8led
for potential encounters with the laser
beam by pl8Dt personnel, bystanders.
and wildlife. The list of reference.
Includes manuals with detailed
requirements used by EPA operators to
- prevent exposure of individuals to the
laser beam. This Ust In addition to
Section VD of Reference 5.1. is
Indicative of the thorough safety training
that is an Integral part of the EPA
operator-tralnins program. EPA
operators must verify that no plant,
personnel are In the vicinity of the laser
beam. Thi. Is accomplished visually and
the procedure is repeated anytime the
Udar II directed close to the Up of a
Itack or other source. The Federal
Aviation Administration (FAA) is
latisfied with EPA precautions. Flight
paths near 8D Intended source are
reviewed prior to a test and the FAA is
notified of the testing in a particular
area. The required operator vigilence
prevents an accidental exposure to the
direct laser beam by the public or by
wildlife. The regulation does not specify
safety procedures because EPA's
position is that the adoption and
practice of laser safety in the field Is
Incumbent upon any owner/operator of
a lidar. Any Udar manufacturer can
provide training in lidar safety
(References 48 and 49 of the Technical
Support Document). The purpose of this
regulation Is to provide a method for
measuring plume opacity by Udar.
Section VD of the Technical Support
Document [Reference 5.1] describes
adequate laser safety requirements and
procedures when applied to field use.
The aiming telescope Indicates where
the laser beam will strike the emi88ion
source when the lidar range in
determined. The operator may use a
variety of visual aides to determine that
no employees are working on a stack or
other source that is to be tested. The
lidar will not be operated when there is
a reasonable. though slight. probability
that people or animals will intersect the
laser beam. Similarly, objects that could
reflect a laser pulse intact are avoided.
The diffuse reflection of a laser beam
from an opaque object does not present
a hazard to the public or to the lidar
operators. A prior notification of
Intended source testing was not added
to the regulation as requested by several
commentators. The present safeguards
241
are adequate for protecting employees
and a notice requirement could limit
enforcement applications.
One commentator questioned liIe
Agency's ability to enforce the
restriction on operator uae of dullin&
dross or medications prior to or durmg
lidar operations. EPA based these
restrictiona upon safety regula tioru;
specified for the operator of
sophisticated or powerful equipment
that presents a potential risk to the
public. such as an aircraft pilot. It is the
Individual responsibility of lidar
operators to avoid the use of any
substance which will impair their senses
or their ability to operate the lidar
.afely. Abuse of this restriction may be
detected by other operators or by an
operator's Inability to perform
satisfactorily. EPA clearly emphasizes
the individual'. responsibility in laser
safety during the training program.
Several commentators noted that the
running average method for the Udar
determination of average opacity values
contradicted the Method 9 calculation.
EPA deleted the running average
requirement from the alternate method.
and replaced it with the calculation for
the average of actual opacity.
Comments regarding the discarding of
opacity values Indicate the need for an
explanation of quality control and the
linkage of the altemate method with the
variations of the reference method. The
reference or ambient air signals required
during a test maintain the accuracy and
precision of the altemate method. Only
measurements that provide high quality
data are used for compliance
determination. The acceptance/rejection
criterion assures the objectivity of the
altemate method and further reinforces
the accuracy of the results. The
requirement that the associated
standard deviation. So. for a lidar.
determined opacity value be less than or
equal to 8% (full scale). accounts for the
variations that are inherent to Method 9
observations.
Several commentators suggested that
quality assurance procedures are a vital
aspect of any system. The Agency
agrees with this observation and
continued the requirements for lidar
performance verification. This Includes
annual calibration of a lidar system.
routine equipment calibrations.
refererence measurements (ambient air
shots). and an acceptance/rejection
criterion. Additionally, collaborative
tests were conducted to verify the
correlation between opacity values
determined by lidar and those
determined by certified visual emissions
observers. The test results were
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Federal Register I Vol. 46, No. 208 I Wednesday, . October 28. 1981 I Rules and Regulations
53147
incorporated into the data reduction
techmque to provide high quality data,
Other commentators mentioned
apparent subjectivity of the lidar
operator in determining plume opacity
values. The alternate method
requirementl virtually eliminate
subjectivity. The individual
characteristici of each lOuree will
control positioning and use of the lidar
system. These judgments are no more
subjective than those required by the
reference method. The alternate method
produces more objective data because
lidar is less restricted. and is able to
compensate or correct for plume drift.
The opera tor is able to visuaIly verify .
that the lidar measurements are free
from interference.
Commentators correctly perceived
that training is'required to produce lidar
operators. Some commentators felt that
EPA should institute a certification
program for Udar operators. EPA
decided not to make a lidar operator
certification program a part of thi,
alternate method because proper and
adequate training in lidar operatioDlI8
the responlibWty of the lidar ownerl
operator and i, readily provided by any
number of lidar manufacturers.
EPA expects that the performance
verification of the lidar will be
performed by the personnel who will be
operating the system in the field using
this method. U a lidar I. not properly
operated. it will not fulfill the
performance verification requirementa
of this method.
EPA's experience with the training.
certIfication and use of non-specialized
trainees has been successful Usually
lidar manufacturers will offer trainin&
for prospective lidar operators.
Cemments were made concerning the
availability of lidars and lidar
equipment. Several contractors located
throughout the country offer the
manufacture or lease of lidar systems.
Other comments were directed
toward the availability of Udar data.
EPA policy encouragll the
dissemination of information to the
public. Udar-generated data will be
available to the same extent that data
obt81,ed by EPA visible emission
obse --;ers is available.
A , review of one commentator's
obse. 1tion of the improper application
of a m thematical formula, the
appropriate corrections were made in
the "i ternate method. Derivation. for the
formulas in the alternate method are
contained in the Technical Support
Joc~ment [Reference 5.1).
Ar.other commentator speculated
u;::on undefined problems and
unobserved interferences. EPA will deal
with speculative problem. when they
are encountered.
One commentator contended that the
use of a lidar .ystem was
unconstitutional. but failed to provide
any reasoning or I..al authorltie. to
support thi. 81'8U1Dent. In any event, It 18
without merit.
Stack plume. are visible from "plain
field." and the Con.titution dOli not bar
air pollution enforcement official. from
enforcing .tandardl by obl8rvin& and
mea.uring the opacity of .uch plume..
Air Pollution Variance Board of
Colorado v. We.tem Alfalfa C017J.. 410
U.S. 861 {1974). An owner or operator ol
such a stack doe. not have a reuonabl.
expectation that the opacity of .uch
plumes will not be ob.erved and
measured. Therefore, such obl8rvation
and mea.urement does not coDititute a
"..arch" under the Fourth Amendment.
See, Katz v. United Stats.. 35U.S. 347
(1987). Such observation and
mea.urement doe. not become a
"eearch" .lmply becau88 It 18 performed
by a mechwIID .uch a. lidar, that
make. the mea.urement more reUable.
and allOWI measurement at niPt.
Unit«l State' v. LeI. 214 U.s. 558. 583
(1927); State v. Stachler. 570 P. 2d 1323
(Haw. S. Ct. 1977): Burkholder v.
Superior Court. 158 Cal Rptr. 88 (Ct.
App. 1979). ,
The commentator allO objected that
EPA lacks statutory authority to
authorize the enforcement of opacity
limits by Udar. He IIJ'IUed that EPA i,
not authorized to use "remot.,
surreptitious. non-Bntry" meana ol
enforcement. Thia 81'8U1Dent 18 without
merit.
Section 114 01 the Clean AIr Act 18 a
broad grant 01 authority to .ample
emiasioDi. It provide. that. lor the
purpo.es of carrytq out virtually aU
provisions of the Act. Including
enforcement of state Implementation
plana and new .ouree performance
standards. "the Admini.trator may
require any person who own. or
operat88 any emlllion .olifce" to
"instalL use, and maintain .uch
monitoring equipment or method.," and
"sample such emis.ion. (in accordance
with such methode. at such location., at
such interva18, and In such manner a.
the Administrator may prescribe). . .
a. he may rea.onably require" and that
the Administrator may "!am,le any
[such) emiaaions," Section 114(a)(1).
(2)(8). Because lidar 18 a reliable me8DI
of sampling the opacity of emls.lOM and
of monitoring the performance of
pollution control techniques. the
Admini.trator may reasonably aUow Ita
UI8.
There is nothing In the language or
legislative history of Sect.ion 114 to
242
'ug88t that ifa sampling or monitoring
technique can be used from out.ide the
boundariee of a pollutin& plant without
the owner'. knowledge. It may therefore
not be used a. an enforcement
technique. Indeed. EPA h.. required the
use of Method 9 to momtor and sample
.mlssloDl lince 1m, 36 FR 24876. 34895
(Dee:. 23, 1971), and Method 9 can be and
18 used from outside plant boundaries
without owners' knowledaa. The use of
Method 9 hat been upheld a. a
rea.onable enforcement technique.
Portland Cement Association v. Train,
513 -F.2d 506. 508 (D.C. Cir. 1975).
FlnaUy. Section 301(a)(1) makes it
clear that the Administrator may
exerci88 his authority under Sectio.n 114
by resuiation.lt provides. ''The
Administrator Is authorized to prescribe
IUch resulation. a. are nece88ary to
carry out hialunction. under this
chapter [the Act)." Therefore. the
Admini.trator hat the authority to
prelCribe by regulation the manner In
which Udar may be used.
Another commentator objected In
general terms that the ruiemakiDg ha.
not complied witl1.Section 307(d) of the
Act. but did not mention any specific
defect. EPA agreee that the ruiemaking
I. governed by Section 307(d). but
believe. that It fully complin with that
..ction.
Thi. commentator also objected that
EPA 18 required to provide opportunity
for hearings on thi. rulemaking in every
state of the United States, under Section
11O(c)(l). of the Act. This appears to
refer to EPA', regulatioDi on Approval
and Promulgation of Implementation
Plana, 40 CFR Part 52, which provide. in
the General Provision.. I 52.12(c) thet
Por Ibl purpo.e or Pederal enforcement, the
followtna test procedure. Ihall be used:
(1) Sources .ubject to plan proviaiolll
wbich do not specify a te.t
procedure' . . will be talted by mealll of
the .ppropriete procedure. and method.
prnc:ribed In Part 60 or tbi. chapter' . .
Thi. provision. promulgated on May
31, 1972 (37 FR 10842. 18847). has
governed all state planl approved under
the Clean Air Act. It merely provides
that where a state has not specified a
procedure for testing alource's
compliance with It I plan. EPA will use
the appropriate FederaUY-Bltablished
telt method.
The commentator implies that
because 40 CFR 52.12(c) allows EPA to
use Part 60 methode to enforce state
pl8DI. a rulemaking adding lidar to the
Part 60 methods reqJJ.ire. a hearing in
each state. This i. incorrect.
Section 110(c)(1) requires EPA to hold
a hearing in a state only where the state
ha. failed to submit an approvable
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53148
Federal Register I Vol. 46. No. 208 I Wednesday. October 28, 1981 I Rules and Regulations
implementation plan. and EPA
lhereupon promulgates a plan for that
slale. This rulemaking does nol deal
with such a case. It merely establishes
an alternate test method that may be
used to enforce a state plan where a
state has not otherwise provided.
Section 110 does not require that
regulations of national applicability
affecting state plans may be adopted
only after opportunity for 55 hearings.
one in each state.' Indeed. all such
regulations have been promulgated
without opportunity for a hearing in
each state. See 40 CFR Part 52, Subparts
A and EEE and Appendices. and Part 51.
In particular. EPA has from time to time
revised and updated ita test methods. as
it is now doing for Method 9. EPA has
done so in every case by rulemakings
without providing opportunity for
hearings in every state. See generally 40
CFR Part 60. Appendix A (1980).
Section 307(d) also makes clear that
Congress did not intend to require
multiple hearings for rulemakings
governing implementatioD plana. SeCtiOD
307(d) establishes procedural
requirementa for EPA rulema1dngs.
including all rulemakings relating to the
prevention of significant deterioratioD
("PSD"). PSD rulemakings, both before
and since SectioD'307(d) was added to
the Act. have taken the form of
regulations amending all state plans. or
governing all state plans. See. 40 CFR
52.21 and 51.24 (1980). SeCtiOD 3D7( d)(5).
however, requires only a single public
hearing for such rulemakings. EPA
therefore fully complied with the Clean
Air Act by holding a single public
hearing for this rulemaking.
Finally, ther~ was DO reason to hold
more than one hearing. Only seven
persons requested 8 hearing. No one'
requested additional hearings, or gave
any reason why hearings in other states
should be held. Indeed, the commentator
waived a request 'for any hearing. Since
there was DO rea SOD to hold additiODal
hearings. it was lawful for EPA not to
hold them. See American Airlines Inc. ...
CAB. 359 F. 2d 624, 632~3 (D.C. Cir.
1966); CleaD Air Act SectioD'
307(d)(9)(D)(I), (ill).
Applicable DocumentatioD
This alternate method is Issued under
the authority of Sections 111, 114, and
301 of the Clean Air Act. as amended (42
U.S.C 7411, 7414. 7601). -
The docket, Number A-79-41. Is
available for public inspection and
copying between 8:00 a.m. and 4;00 p.m.
I Under the Clelll Air Act, "ilale- II denned 10
Include the 50 Ilal... piUlII.... other a",al. Sectioa
302(d). Each 01 the 55 -Itata" bal a pi... 40 CFR
Pari S2. Subpanl &-DDD.
at EPA's Central Docket Section. Room
2903B. Waterside Mall. 401 M Street.
S.W., Washington. DC 20460.
Under Executive Order 12291. EPA
must judge whether a regulation is major
and therefore subject to the
requirements of a Regulatory Impact
Analysis. This regulation is Dot major
because the annual effect on the
economy is less than $100 million. This
is an alternate test method to an existing
. enforceable test method. It imposes no
new regu1atory requirementa. The use of
this alternate method is optional for
opacity determination.
This regu1ation was submitted to the
Office of Management and Budget
(OMB) for review as required by
Executive Order 12291.
Dated: October 19, 1981.
Alma M. Gonuch.
AcJmjniBtratDr.
PART SO-STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
EP A Is amending 40 CFR Part 60,
Appendix A by adding an alternate
method to Method 9 8S follows:
Appendix A-Refer8Dce Methods
Method t-VIauaI Determiuadoa of the
OpacIty or Emiul0D8 From 8&atiGDuJ
SOIII'C8tI
AJlem8te Method ~.....I...u- or !be
Opadty of Emiaaiona FI'OID StaIioDary
SOIll'C8l Remotely by Udu
Thia alternate method proYidee the
quantitative determination of the opacity of
iUI emi.liona plume l'I!DIotely by 8 mobile
Udar .)'8tem (181er radar: Ugh! Detection aud
Ranging). The method Includee procedUl'el
for the calibratiOD of the Udar and procedUl'el
to be uaed In the field for the Udar
determinatiMl ofplUIDe opacity. The Itdar Is
lAsed to meaaure plume opacity darin& either
day or nighttime hours becaaae it contalna it.
own pulaed Ught 10urce or tranamitter. The
operation of the Udar i. not dependent upon
ambient lighting conditioD8 [light, dark. .unny
or cloudy).
The lidar mechanillD or technique is
applicable to measuring plume opacity at
nwneroua wavelengtha of laaer radiation.
However. the perfonDauce evaluation and
calibration l88t re.uIta given In aupport of
thil method apply only to a lidar that
employa 8 ruby {red light) luer [Reference
6.11.
1. Principle and AppJjCDbiJity
1.1 Principle. The opacity of Yilible
emissions from stationary sources [stacks.
roof vents. etc.) is measured remolely by a
mobile lidar [laser radar).
1.2 Applicability. This method is
applicable for the remote meallUrement of the
opaci~ of visible emissions frOM stationary
243
aources during both nightltme and dayil"'"
conditIOns. pursuant to 40 CFR i 6O.11[b, It IS
allo appucable for the calibration and
perCom:.nce verification of the mob,le iIdar
for the measurement of the opacity of
emissions. A perfonnance/design
specificat'on for a basic lidar system is also
lacorpora!~d Into this method.
1.3 Deiinil1oDS.
Azimuth angle; The angle In the horizontal
plane that designates where the laser beam i.
pointed. 11 is measured from an arbitrary
fixed reference line In that plane.
Backscatter: The Icattering of laser light in
a direction opposite to that of the incident
laser beam due to reflection from particulates
along the bealD's atmospheric path which
may Include e aMoke plume.
Backscatter lignal: The generaltenn for the
lidar return signal which relults from laser
light being backlcattered by atmolphenc and
smoke plume particulates.
Convergence diatance: The distance from
the lidar to. the point of overlap of the Lidar
receiver'. neld~f-view and the laser be.am.
Elevation angle: The angle of inclination of
the la"r beam referenced to the borizontal
plaue.
Far resion: The region of the atmosphere's
path along the lidar line-of-light beyond or
behind the plume being measured.
Udar: Acronym for Ughl Detection and
Ranging.
Udar range: The range of diatance from the
lidar to 8 point of InteJ'elt along the lidar line-
of-lighL
Near resion: The resion of the atmospheric
path along the lidar line~f'light between the
Udar'a convergence distance and the plume
being meaaured.
Opacity: One mlmta the optical
trananittance of 8 SIIIOke plume. laeen
target, ete.
Pick Interval: The time or range Inte"81s ill
the lidar backacatter aignal whole miIumum
aVllfqe amplitude is uaed to calculate
opacity. Two pick intervals are required. one
In the near region and one In the far regton.
Plume: The plume being measured by lidar.
Plume signal: The backlcaller signal
resulting from the laeer light pulee paulDg
through a ;llIune.
1/R' correction: The correction made for
the IYltemalic cIeere..e in lidar backscstter
signal amplitude with range.
-Reference signal: The backacalter signal
relulting from the laser light pulse passlDg
through ambient air.
Sample Interval: The time period between
8uccessive samples for a digi tal signal or
between luccessive measurements for an
analog lignal.
Signal Ipike: An abrupt. momentary
inaeaae and deaease in lignal amplitude.
Source: The aource belDg tesled by lidar.
Time reference: The time (1,,) when the
laler pulae emerges from the laser. used as
the reference in alliidar time or range
measurements.
Z. Procedure$.
The mobile lidar calibrated in accordance
with Paragraph 3 of tJus method shall use the
following procedures for remotely measunng
the opacity oC statioDary source enu.ssIODS:
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Federal Register I Vol. 46. No. 208 I Wednesday. October 28. 1981 I Rules and Regulations
53149
~1 Lidar POlition. Th.lidar lhall be
po.illoned at . distance from the plume
sufficllnt to provide .n unobltructed view 01
Ihe source emluionl. Th. plume must b. at a
range of at le8lt 50 meters or three
consecutive pick intervall (whichever i.
grealer) from the lidar'. tranlautter/receiv.r
convergence diltance aloll8 the line-ol-light.
The maximum effective opacity mealuremlllt
dIStance of the lidar II a function 01 local
atmospheric condition.. la8lr beam diameter.
and plume diameter, Th. t88t polition of tha
lidar Ihall be ..Iected 10 that the diameter 01
the laser beam at the me8lurement point
with," the plume Ihall be no larger than
Ihree-fourth. the plume diameter. The beam
dIameter is calculated by Equation (AM1-1):
D(lidar)=A+R...O.75 D(Plume) (AM1-1)
where:
D(Plume) = diameter of the plume (cm).
. = laler beam diversence measured in
radianl
R.. range from th. lidar to the sourc. (em)
D(Lidar = diameter of the !allr beam at ranp
R{cm).
A.. diameter 01 the la18r beam or pula.
where it leavea the lallr.
The lidar ranse. R. la obtained by aimID8
and firing th.laler at the emiaaiona ao-
structure immediately below the outlet. ne
range value If then detennin.d from the
backscatter silJllal which conaiata of a allJllal
spIke (retum from source ItruCture) and tha
atmospheric backac.atter .ll"al [Reference
5.11. Thil backscatter aignalahould be
recorded.
When there ia more than one lource of
eml8..ona in Ihe immediate vicinity of the
plume. the lidar .hall be position.d 10 that
Ihe Idser beam pallea throU8h only a ain8l.
plume. free from any interference of the oth8r
plumes for. mlmmum of 50 meters or three
consecullve pick ,"tervala (whichever ia
grea ter) in each region before and beyond the
plume along the line-of-.ight (detennined
from the backscatter aignal'l. The lidar aball
imllally be pOlitioned 10 that ita line-ol-.ight
IS .ppro..lmately perpendicular to the plum..
\\i !.en mealuring th. opacity 01 eausaiona
from rectangular oulleta (e.g.. roof monitors.
open baghou"I, noncltcular stack.. etc.I, the
hdar shall be placed in . position so that ita
line-of.sight.a appro..imately perpendicular
10 the longer (major) a..,s of the outlet.
2.2 Lldar Operallonal Restriction.. The
hd.r receiver shall not b. aimed within an
an~le of == 15' (cone all8le) of the .un.
This method shall not be used to make
opaCil y measurementa If thunderstorms,
6nu,", storms. hailstonna, high wind, high-
ambient dust levell. fog or other atmospheric
condl'lons cause the reference silJllal.to
cons" 'ently e..ceed the limits apecified in
Sect11 '2.3.
2.3 'eference SilJllal Requirementl. Once
placel 1 Its proper position for opacity
medSUI "ltent, the laser is aimed and fired
with ,,,. line-of-sIght near the outlet beight
and rolated hOrizontally to a position clear of
the suurce slructure and the associated
plume The backscatter signal obtained from
Ihls pOSlllon IS called Ihe amb"nt-aor or
reference signal. The lidar operator shall
Inspect IhlS SIgnal [SectIon V of Reference
5 1110: (11 delermllle If the hdar hne-of-sight
" :,,'e from Interference from other plumes
and from phyaical ob.tructione luclt as
cable.. power Un... etc.. for a minimum of 50
meters or threa conlecutlve pick intervala
(whichever ta greater) in each rqlon before
and beyond the plume, and (2) obtain a
qualitative meaaure of the homogeneity of the
ambient air by noting any lignal .pike..
Should there be any algnal apikea on the
reference aignal within a minimum of 50
mete... or three COllHCUtive pick Iuterva18
(whichever I. greetar) in each rqlon before
and beyond the plume. the In.. Ihall be ftred
three more 11m.. aDd the opere tor ahall
inlpect the refetellce lignall on the dI.,lay. If
the Ipike(l) remaine. the azimuth angle .ball
be chall8ed and the above procedurel
conducted agaiD. U the Ipike(l) dillppeara in
all three reference lignal., the lidar Une-of.
aight il acceptable if there II .hot-to-Ibot
conaieteacy 8Dd there II no interference from
other plume..
Sbot-to-ahot conlistency 01 a .eriel of
reference aignal. over a period of twlllty
aeconda la verified in either 01 two ways. (11
Th. IIdar operetor Iball ob.enoe the reference
aignal amplilllde.. For ahot.to-ehot
collltltanCJ the retlo of R, to R" [amplitudea
of the near 8Dd far reaton pick interva18
(SectIon 2.11)) .ball vary by not more than %
6"" between .boll; or (2) the lidar operator
ahan accept anyone 01 tha refereau lf8na18
and treat the other two a. pluma algna18; then
the opecity for .ech of the .ub.equent
ref.rence lignal8 i. calculated (Equation
AM1-a). For .bot-to-ahot conalatency. the
opacity valuea aball be witllin % 3"" of~
opacity and the e.eoc:Ietad Ii. valuel Ie..
than or equal to 8"" (fuI1ecale) (Section 2.11.
U a lit of ref.renc. aignal. faile to meet the
requiramenll 01 thi. aectioD. then all plume
aignala [Section UJ from the la.t lit of
acceptable reference aignal. to the failed .et
Ihall be dI.carded. -
2.3.1 initial and FlDal Reference Signata.
Three reference lignala ahall be obtained
wi thin a 9I).aecond time period prior to an,
data run. A nnal lit 01 three refarenea lignal8
aball be obtained within three (3) miDUtll
aftlr tII. completion of the lame data run.
2.3.2 Temporal Criterion for Additional
Reference Signala. An additioneillt of
reference signall shall be obtained during a
data run if there is a chanse in wind direction
or plume drift at 30' or more from the
direction that was prevalent wh.n the Int lit
of reference aignall were obtained. An
addltionel aet of reference I;gnall ahall alao
b. obtained if there la a cbanse in amplitude
in either the near or the far region of the
plume lignal, that il greater than 6"" of the
near .ignal amplitude and thil change in
amplitude remainl for 30 leconda or more.
Z.. Plume SilJllal Requirementa. Once
properly aimed. the lidar il placed in
operation with the nominal pulee or firin8
rate of six pulaea/minute (1 pulee/10
aeconda). The lidar operator ahall obaerve the
plum. backscatter silJllall to detennine the
need for additional reference .llJIIals a.
required by Section Z.3.Z. The plum. signal.
are recorded from lidar start to atop and are
called a data run. The length of a data run ia
determmed by operator discrelton. Short-
term slop. of the lidar to record additional
reference sIgnals do not conslltute the end of
a data run u plume signals are resumed
244
within 90 ..cond. after the reference signala
bave been recorded. and the total .top or
luterrupt time does not exceed 3 minutes.
2.4.1 Non-hydrated Phlllles. The laser
..all be aimed at the resiOll of the plume
which diaplaYI the greateat opacity. The lidar
opere tor must vI.uaUy verify that the l8Ier is
aimed clearly above the lOurce exit atructure.
2.4.2 Hydrated Plumel. TheUdar will be
used to me..ure the opacity 01 hydrate4 or
eo
-------
53150
Federal Register I Vol. 46. No. 208 I Wednesday. October 28. 1981 I Rules and Regulations
hne. The lidar operator should also observe
color differences and plume reflectivity to
detect e detached plume. IT the operator does
not obtain a clear iIIdication of the location of
the detacbed plume. this method ehall not be
used to make opacity measurements between
the-outlet and the detached plume.
Once the determination of a detached
eteam plume hae been confl/'llled. the laser
shall be aimed Into the region of highest
opacity In the plume between the outlet and
the formation of the eteam plume. Aiminll
adjustmente ehan be made to the lidar's line-
of.eight withiu the plume to comict for
chanllee in the location of the moet denee
rellion of the plume due to chanllee ID wind
direction and epeed or if the detached sleam
plume movee cioeer to the eouree outlet
encroaching on the mostdenae rellion of the
plume. IT the detached steam plume should
move too close to the source outlet for the
lidar to make interference-free opacity
measurements. this method shall not be used.
2.5 Field Records. In addition to the
recordinll recommendatione listed In other
sectione of this method the fonowinS records
should be maintained. Each plume measured
should be uniquely identified. The name of
the facility. type of facility. emilsion source
type.lleOllf8phic location of the lidar with
respect to the plume. and plume
characteristics ehould be recorded. The date
of the test. the time period that a source wae
monitored. the time (10 the nearaet eecond) of
each opacity measurement. and the eample
interval ehowd also be recorded. The wind
245
speed. wind direction. air temperature.
relative humidity. visibility (measured at the
lidar's position), and cloud cover should be
recorded at the beBinninll and end of each
time period for a Biven source. A small sketch
depictinll the location of the laser beam
within the plume sbould be recorded.
IT a detached or attached steam plume is
present at the emissions source. this fact
should be recorded. FilJW'l!s AMl-1 and AMl-
n are examples of 10llbook forms that may be
uaed to record this type of data. Magnellc
tape or paper tape may also be used to record
data.
IIUM8 CODE -
-------
UDU UIe; UIIHlm. '.I.U HI' UTlO'
I... 1..0" '.m.rr-
III'ill . coUIIL IUIIIU II ud ..'i,i...1 'U'CI ...., tull
N)
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0\
coUIIL DIn
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.
,
cut,.... II .... ,...
!.IiIU UIe; UII\THIII, "'IIH.H 1 \K'Ln 1111\ ("0111')
111,11' . CIIITIOL ..UIIIU II ue' 11",,,..1 ,u,u "'" tllil
con.IL IUE
..IIIU USiClU ..llEet ~ITY. nUE
-
....t L.. h.. ....h,-
Figure ANI1-1 Lid.r Log Control Number T..bul.lion
...,
<11
c-
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-
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=
iii
...
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::I
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c:
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..
en
w
...
en
...
-------
1.11. \N 1.111. OJ. "PU HI"'"
,...".1 ...1,..,: ,..... ,-
...1111, .... ... 1...11..
al'" fl,t' I'" II
",1,18. I' &II..'
I".
- ,.
II...' "..1
lultl.1I '1 ...". ..... t. 'II'U
1111' .Ich...... I' 11"1 '1 II h.uIIUI II . I
...". '''' ... .Uhlll '""""""
..
..... .h"tllIl,"" h,I... '''''' ..... ,r....'. .....
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.... .,..." "1.1 _'.'11. ... _'a III .'1' 'hl.II.." hili ",-
'It ...,.,.1... hili - C..- - C .,1,.... ..."11, "1" -', "' ~ "
h,...... 81,". III' '''.111111,- 11'1" - II. ,., ,.
(I,d n.., "1'111 ...
._._._._._~_._._._._._._._._._._._._._._._._._._._._.-.
"1' ....... .... .. ,..., tit,... ,......... ""1 to ... I.
..'.llIt "'IS
~~~
.-.-.-.-.-.-.
.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.
O',U'OI 11"1611'"
OUI.
....,11 1"1611"
Uti,
LID U "ru ""R"S 'fins
I'"'''' 0..11111 .1 ..... .... .IUI. .1...-- .11..... .1.... .Ie ,
.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.
S..'U' I,IICII .1"""' I I IU"" I I
1111111111 'leI"I'" ,.,.-_I..C"-
I . I I ,
11.&1 111(11.. '''.11(&1101
1.,. ., ,... nll,..II..
I
bll,..II' "'Cfl, -
hlul.I" ,,"11, -
hu.." .. 'II.
""1f...1 I.OIU....
.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.
u",
...1111 IlIla....,
fIgure AM1-11 Lldar Log 01 OperatIons
u",
en
""
...
en
N
"'I
II
Co
II
!.
:;a
II
3Q
Iii.
S'
..
-
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-------
federal Register I Vol. 48. No. 208 I Wednesday, October 28, 1981 I Rules and Regulations
53153
t
C1I
"0
~
... to
Co J
E
«
t
C1I
"0
~
...
.- to
~
Co J
E
«
(a> Reference Signa', 1/R2 Corrected
(Ne.r Re.gion)
(Far Region)
Convergence Point
1 -
Rf
~--
Rn
-~
Time or Range
(b) Plume Signa', 1/RI Corrected
/Plume Spike
/
,.
-----...
'n
If
Time or Range ~
(a)
Reference signal, l/R2-corrected. This reference signal is for
plume signal (b). Rn" Rf are chosen to coincide with In" If'
(b)
Plume signal, l/R2-corrected. The plume spike and the decrease
in the backscatter signal amplitude in the far region are due to
the opacity of the plume. I 7 If are chosen as indicated in
Section 2.6. n
Figure AM1-1II.
Plots of Lidar Backscatter Signals
a'LciNG CODE 6560-..c
248
-------
53154
Federal Register / Vol. 46. No. 206 / Wednesday. October 28. 1961 / Rules and Regulations
2.6 Opacity Calculation and Data
AnalysIs. Referring to the reference signal
and plume signal in Figure AMl-lI1. the
measured opacity (0.1 in percent for each
lidar measurement is calculated using
Equation AMI-2. (0.=1- T,.; T. is the plume
transmittance.)
Op = (10~) [ 1 - ( ~ Rn )
Rf In
(AMl-2)
where:
I. = near-region pick interval signal'
amplitude. plume signal.l/R2corrected.
Ir=far-region pick interval signal amplitude.
plume lignal. l/R 2 corrected.
R,. = near-region pick Interval signal
amplitude. reference lignal. l/RI
corrected. and
R,= far-region pick Interval lignal amplitude.
reference signal.l/R2corrected.
The l/R 2 correction to the plume and
reference signal amplitudel il made by
multiplying the amplitude for each luccessive
lample interval from the time reference. by
the square of the lidar time (or J1UIge)
associated with that sample interval
[Reference 5.11.
The first Itep in lelectlns the pick intervall
I -
f -
The standard deviation. 5,.. of the set of
amplitudes for the near-region pick interval.
I.. shall be calculated using Equation
(AMI-5).
[ m (Inf - In
SIn - I
f=l (m-1)
)2] It
(AM1-S)
Similarly. the Itandard deviatione Su. s..,.
and SRI are calculated with the three
expressions in Equation (AMl~).
Slf .
[ m (
- I
f=1
I fi - If
(m-l)
)2] It
So
1 ( If Rn )" [ ~~/ +
2 Rf In In
=
The calculated valuel of 1..1,. R.. R,. s,.. s".
SR.. So,. 0.. and S. should be recorded. Any
plume signal with an S. greater than 8% shall
be discarded.
2.6.1 Azimuth Angle Correction. IT the
azimuth angle correction to opacity specified
in this section is performed. then the
eleva tion angle correction specified in
Section 2.6.2 shall not be performed. When
opacity is measured in the residual region of
an attached steam plume. and tbe lidar line-
,,}
for Equation AMI-2 is to divide the plume
signal amplitude by the reference signal
amplitude at the same respective ranges to
obtain a "normalized" signal. The pick
intervall selected using this normalized
signal. are a minimum of 15 m (100
nanoseconds) in length and consist of at least
5 contiguous sample intervals. In addition.
the following criteria. lilted in order of
importance. govern pick interval selection. (1)
The intervall Ihall be in a region of the
normalized lignal where the reference signal
meets the requirements of Section 2.3 and is
everywhere greater than zero. (2) The
Intervals (near and far) with tha minimum
average emplitude are chosen. (3) IT more
than one Interval with the same minimum
average amplitude is found. the interval
clolelt to the plume il chosen. (4) The
Itendard deviation. s.. for the calculated
opacity shall be 8% or less. (5. II cr.lculated
by Equation AMl-7).
IT S. II greater than 8%. then the far pick
interval shall be changed to the next interval
of minimal average amplitude. IT S. is still
greater than 8%. then thl. procedure is
repeated for the far pick interval. This
procedure may be repeated once again for the
near pick interval. but If S. remains greater
than 8%. the plume signal shall be discarded.
The reference signal pick intervals. R. and
R,. mUlt be cholen over the same time
1 .
- I If' .
m f=l 1
.
I Rn; .
i=l
1
m
R = 1
f II
Rn
=
SRn
L~l
(R - R )2]"
ni n
(m-l)
::
SRf
[ m (Rff - Rf
= I
i=l (m-1)
)2 ] It
interval as the plume signal pick intervals. I,
and I,. respecllvely [Figure AMl-lIIl Other
methods of selecting pick 1Oter\'als r.'.J' be
used if they give equIvalent results Fie Id-
oriented examples of pick 10terval selectIOn
are available in Reference 5.1.
The average amplitudes for each of the
pick intervals. I.. I,. R.. R" shall be calculated
by averaging the respective indIvidual
amplitudes of the sample intervals from the
plume signal and the associated reference
lignal each corrected for I/R '. The amplitude
of I. shall be calculated according to
Equation [AM-3).
In
!
m
m
I
i=l
(AMI-3)
I .
n1
=
where:
I.,=the amplitude of the ith sample interval
(near-region).
I = sum of the Individual amplitudes for the
sample intervel..
m = number of sample intervals in the pick
interval. and
I.=average amplitude of the near-region pick
interval. -
Similarly. the amplitudes for I,.-R.. and R,
are calculated with the three expressions in
Equation (AMI-4).
m
I
i=1
Rf; .
(AM1-4)
Figure AMI-IV(b) shows the geometry of
the opacity correction. L' is the path through
the plume along which the opacity
measurement is made. P' is the path
perpendicular 10 the plume at the same point.
The angle 0 is the angle between L' and the
plume center line. The angle (../2-0). is the
angle between the L' and P'. The measured
. opacity, 0.. measured along the path L shall
be corrected to obtain the corrected OpaCIty.
0... for the path P'. using Equation (AMl-8).
(AMl-6) I
o = 1 - (1 - 0 )Cos (n/2-£)
pc p
The standard deviation. SO' for each
associated opacity value. 0.. shall be
calculated using Equation (AMI-7).
5If2
P
f
+
S 2
Rn +
p
n
SRf2 ] 't
P
f
(AM1-7)
of-sight is not perpendicular to the plume. it
may be necessary to correct the opacity
measured by the lidar to obtain the opacity
that would be measured on a path
perpendicular to the plume. The following
method. or any other method which produces
equivalent results. shall be used to determme
the need for a correction. to calculate the
correction. and to document the poml within
the plume at which the opacity was
measured.
249
= 1 - (1 - 0 )Sin £
p (AMI-B)
The correction in Equation (AMl-81 shall
be performed if the inequality In EquatIOn
(AMI-9) is true.
£
~
S;n-'
[
1n (1.01 - °D) J.
1n(1-0)
p
(AMI-g)
Figure AMI-IV(a) shows the geometry
used to calculate 0 and the posItIon In the
plume at which the lidar measurement IS
made. This analvsis assumes that for a given
lidar measurem~nl. the range from the I. ddf
to the plume, the elevation angle of the i,dJr
from the hOrizontal plane. and the aZIer. ,:n
angle of the lidar from an arbllrary f"eJ
reference 10 the hOrizontal plane can "" tJl'
oblained directly
BILLING CODE S560-38-M
-------
Projection of Ponto
p
I
)(
NI
(j1
o
Lidar line-of-Sight.
Position' p
(b)
IILLIHG COIlE _38-(:
the yz-plane, P p" P1ulle luasurement
/'i".,~6 /
/" '.
. I '
/ . R
RS" /' I p t;
position
Pp (Rp' til'. lip>
Plume drift ang1e position
I , (R .1.' + 0' A >
I a a'''' . "a
I
I
I
I
I
I
I
/
/
/
's (R.. O. p.)
/ Y
- " R / I /
0" - - . R I . ,6 , . / I /
, -. p . I / I /
, -. , /
, """'.-...,.. . - I /
" '-.~L/'roJecUon 01' onto the xy-plane. ,p' /
, " P I /
" ' I /
, , I /
',' /
, R; 'R ' I /
" ',. I /
" , I /
, , I /
',,, /
',' I /
" t /
',' I ~
" /
''V
'roJection 01 'a onto the xy-p1ane. 'a'
(a)
Figure AMI - IV. Cqrrect10n in Opacity for Drift 01 the
Residua1 Region of an Attached Stea8 'lu.e.
..,
~
D-
~
..
!!!.
:0
~
()Q
iii'
;-
..
<
~
".
9>
Z
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~
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o
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en
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...
-
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01
-------
53156
Federal Register I Vol. 46. No, 208 I Wednesday. October 28, 1981 I Rules and Regulations
R,=ran~e from lidar to source'
IJ, =elevdhon angle of R,'
R.=range from lidar to plume at the opacIty
measurement point'
IJ.=elevation angle ofR;
R,=range from lidar to plume a\ some
arbitrary point. P,. so the drift angle of
the plume can be determined'
IJ,=elevation angle ofR,'
a=anjlle between R, and R,
The correction angle E shall be determined
using Equation AM1-10,
where:
a=Cos-' (CoslJ, Cos~. Cosa' +SinIJ, SinJj,),
and
R6 = (R~2
where:
R',=R, Cos ~,. and
R'.=R, Cos~..
In the special case where the plume
I:
where:
R",=(R",+R,' Sin' P,),/"
If the angle E Is such that EO;; 30' or E >
150', the azimuth angle correction shall nOI
be performed and the associated opacity
value sh!lll be discarded,
R',= projection of R. in the horizontal plane
R',=projection of R. in the horizontal plane
R',=projectJon of R, in the horizontal plane
1/1' = angle between R', and R';
a'=angle between R', and R','
Ro=dlstance from the source to the opacity
measurement point projected in the
horizontal plane
Ra=distance from opacity measurement
point P, to the point in the plume P,.
I:
=
Sin-\
[R.S:~ ]
(AMl-10)
Ra=(R,'+R,'-2 R, R, CosaJ1"
Ro, the distance from the source to the
opacity measurement point projected in the
horizontal plane, shall be detenuined using
Equation AM1-11 ,
+
R'2
P
2R' R' Cos",,)1t
s p
(AMl-11)
centerline at the opacity measurement poinl
is horizontal. parallel to the ground, Equation
AM1-12 may be used to determine E instead
of Equation AM1-10,
Cos-J
[ RZ+R2-
p 6
2 Rp Rs
R"2 ]
S '(AMI-12)
2,6,2 Elevation Angle Correction, An
individuallidar-measured opacity, 0" shall
be corrected for elevation angle if the laser
elevation or inclination angle, IJ, [Figure
AM1-V], is greater than or equal to the value
calculated in Equation AMI-13,
In(I.01 - Op)]
In(1 - 0 )
p
Ii > Cos - J [
P -
The measured opacity, 0" along the lidar
path L. is adjuated to obtain the corrected
where:
/3,= lidar elevation or inclinatioll angle.
0, = meBlured opacity along pa th L. and
O..=cOlT8cted opacity for the actual plume
thickness P.
'Obtained directly from lidar These value,
shollid be recorded,
(AMI-13)
opacIty, 0... for the actual plume (horizontal)
path, p, by using Equation (AMI-14),
Q
pc
1 - (1 - Q.)CoSlip
p
(AMI-14)
The values for IJ., 0, and 0.. should be
recorded.
8IWNQ CODE s-
251
-------
Ilorizontal Plane
N)
tJ1
N)
Stack's Vertical Axis
Vertical Smoke Plume
BpI lidar Elevation or
Inclination Angle
l
P
:: Effective Plume Thickness
:: Actual Plume Thickness
P :: lCOSL'
p
0p :: Opacity measured
a long path L
o
pc
:: Opacity value corrected to the
actual plume thickness. P
lidar line-of-Sight
Referenced to level Ground
(Horizontal ~Iane)
(JILLING CODE '~bO-3..C
Smoke Stack
Figure AMl-V.
Elevation An~le Correction for Vertical Plumes.
'TJ
~
ell
..
!.
~
ell
QQ
Cii"
18
..
--
'<
~
.po
9'
Z
?
N
o
C»
--
~
~
o
n
o
a-
ell
..
N
s»
...
S
...
--
~
=
iD
...
II>
::I
0-
~
...
<.II
....
-------
5:311>3
Federal Re;pster I Vol. '46. No. 208 I Wednesday. October 28. 1981 I Rules and Regulations
~.fj.3 Delennmahon of Actual Plume
OpacIty. Ac.ual opacity of the plume shall be
cletennined by Equation AMI-IS.
o
pa
o
pC
[2 So + S~].
(AMI-IS)
=
~.6.4 Calculation of Average Actual Plume
Opacity. The average of the actual plume
opacity. 0... shall be calculated as the
average of the consecutive individual actual
opacity values. 0... by Equation AMl-16.
ii
pa
1
n
I (Opa)k
k=l
=
n
(AMl-16)
where:
(0..). = the kth actual opacity valu!! in an
averaging interval containing n opacity
values; k Is a summing index.
I = the sum of the individual actual opacity
values.
n = the number of individual actual opacity
values contained in the averaging
interval.
0.. = average actual opacity calculated over
the averaging intarval.
3. Lidar Performance Verification. The
lidar shall be subjected to two types of
performance verifications that shall bit
peformed in the field. The annual calibration.
conducted at least once a year. shall be used
to directly verify operation and perfonnance
of the entire lidar system. The routine
verification. conducted for each emission
source measured. shall be used to Insure
proper performance of the optical receiver
and associated electronics.
3.1 Annual Calibration Procedures. EIther
a plume from a smoke generator or screeD
targets shall be used to conduct this
calibration.
If the screen target method is selected. five
screens shall be fabricated by placing an
opaque mesh material over a narrow frame
(wood. metal extrusion. etc.). The screen
shall have a surface area of at least one
square meter. The screen material should be
chosen for precise optical cpacihes of aboul
10. 20. 40. 50. and 60%. Opaci ty of each target
shall be optically determined and should be
recorded. If a smoke generator plume is
selected. It shall meet the requirements of
Section 3.3 of Reference Method 9. This
calibration shall be performed in the field
during calm (as practical) atmospheric
conditions. The lidar shall be positioned in
accordance with Section 2.1.
The screen targets must be placed
perpendicular to and coincident with the
lidar line-of.sight at sufficient height above
the ground (suggest about 30 ft) to avoid
ground-level dust contamination. Reference
signals shall be obtained just prior to
conducting the calibration test.
The lidar shall be aimed through the center
of the plume within 1 stack diameter of the
exit. or through the geometric center of the
screen target selected. The lidar shall be set
in operation for. 6-minute data run .t .
nominal pulse ra te of 1 pulse every 10
seconds. Each backscatter return signal .nd
each respective opacity value obtained from
the smoke senerator transmissometer. shall
be obtained in temporal coincidence. The
data shall be analyzed and reduced in
accordance with Section 2.6 of this method.
This calibration shall be performed for 0%
253
(clean air]. and alleast five olher opacities
[nommallv 10. 20. 40. 60. and 80":].
The av~rage of the lidar opacity values
obtained during a &-minute calibratIOn run
shall be calculaled and should be recorded
Also the average of the opacity values
obtained from the smoke genera tor
transmissometer for the same 6-mmute run
shall be calculated and should be recorded.
Alternate calibration procedures thai do
not meet the above requirements but produce
equivalent results may be used.
3.2 Routine Verification Procedures.
'Either one of two techniques shall be used to
conduct this verification. It shall be
performed at least once every 4 hours for
each emission source measured. The
following parameters shall be directly
verified.
1) The opacity value of 0% plus a minimum
of 5 (nominally 10. 20. 40. 60. and 80~o)
opacity values shall be verified through the
PMT detector and data processing
electronics.
2) The zero-signal level [receiver signal
with no optical sIgnal from the source
present) shall be inspected to insure that no
spurious noise is present in the signal. With
the entire lidar receiver and analog/digital
electronics turned on and adjusted for normal
operating performance. the following
procedures shall be used for Techniques 1
and 2. respectively.
3.2.1 Procedure for Technique 1. ThIs lesl
shall be performed with no ambient or stray
light reachins the PMT detector. The na rrow
band filter (694.3 nanometers peak) shall be
removed from its position in front of the PMT
detector. Neutral density filters of nominal
opacities of 10. 20. 40. 50. and 60% shall be
used. The recommended test configuration is
depicted in Figure AMI-VI.
IIUIHCI CODE --
-------
Federal Register I Vol. 46. No. 206 l Wednesday. October 28. 1981 I Rules and Regulations
Neutral-density
optica-l filter
~
~
PMT Entrance
Window Completely
Covered
(a) Zero-Signal Level Test
CW Laser or
Light-Emitting Diode
Light Source
~
--
1 i ght path
(b) Clear-Air or 0% Opacity Test
, CW Laser or
I Light-Emitting Diode
Li ght Source
~
..
light path
..
....
(c) Optical Filter Test (simulated opacity values)
53159
*
Lidar Receiver
Photomultiplier
Detector
Lidar Receiver
Photomultiplier
Detector
*
Lidar Receiver
Photomultiplier
Detector
.
*Tests shall be performed with no ambient or stray light reaching the
de~ector.
rigure AM1-VI.
Test Configuration for Technique 1.
8IL.l.IHG COOE 6_-..c
254
-------
53160
Federal Register I Vol. 46. No. 208 I Wednesday. October 28. 1981 I Rules and Fegulations
The zpro'sl~nallevel shall be measured
and should be recorded. 8S indIcated in
Fi~ure AMI-VI(a). This simulated clear-air or
J'~ opacity value shall be tested in using the
selecled light source depicted in Figure AMl-
V\(ol.
The lisht source either shall be a
continuous wave (CW) laser with the beam
mech;mically chopped or a light emitting
dIOde controlled with a pulse generator
(rectangular pulse I. (A la.er beam may have
to b~ attenuated so as not to .aturate the
f'MT detector). This .ignallevel .haD be
measured and .hould be recorded. The
opacity value i. calculated by taking two pick
inlervals [Section 2.6) about 1 microsecond
apart i... time and using Equation (AM1-2)
settin~ the ratio R./R,=1. This calculated
value should be recorded.
The simulated clear.air signal level is al.o
employed in the optical test u.ing the neutral
density filters. Using the test configuration in
Figure AMI-VI(c). each neutral density filter
shall be separately placed Into the light path
from the light source to the PMT detector.
The signal level shall be measured and
should be recorded. The opacity value for
each filter i. calculated by taking the sisnal
level for that respective filter (I,). dividing II
by the 0% opacity signal level (I.) and
performing the remainder of the calculation
by Equation (AM1-2) with R./R,=1. The
calculated..llpacity value for each filter should
be recorded.
The neutral densitY fiItel'8 used for
Technique 1 .hall be' calibrated for actual
opacity with accuracy of ~2'11. or better. This
calibration shall be done monthly while the
filters are in use and the calibrated values
should be recorded.
3.2.2 Procedure for Technique 2. An
optical ~enerator (built-in calibration
mechanism) lhat contams a light-emitting
dIode (red light for a lidar containing a ruby
laser' is used. By injecting an optical signal
into the lidar receiver immediatelv ahead of
the PMT detector. a backscatter s'ignal is
simulated. With the entire lidar receiver
electronics turned on and adjusted for no:mal
operating performance. the optical generator
is turned on and the simulation signal
(corrected for l/R") is selected with no plume
spike signal and with the opacity value equal
to O'J{,. Thi. simulated clear-air atmosphenc
return signal is di.played on the system'.
video display. The lidar operator then makes
any fine adjustments that may be neces&aT}'
to maintain the .ystem's normal operating
range.
The opacity values of 0% and the other five
values are .elected one at a time in any
order. The simulated return signal data
.hould be recorded. The opacity value shall
be calculated. This measurement/calculation
.hall be performed at lea.t three times for
each .elected opacity value. While the order
is not important. each of the opacity value.
from the optical generator shall be verified.
The calibrated optical generator opacity
value for each .election should be recorded.
The optical generator used for Technique 2
shall be calibrated for actual opacity with an
accuracy of :t:l'11. or better. Thi. calibration
shall be done monthly while the generator i.
in use and calibrated value should be
recorded.
Alternate verification procedure. that do
not meet the above requirements but produce
equivalent results may be used.
3.3 Devia tion. The permissible error for
the annual calibration and routine
verification are:
3.3.1 Annual Calibration Deviation.
3.3.1.1 Smoke Generator. If the lidar.
255
measured a\'erage opacity for each dal" 'un
is not with'" :::5';, (full scale I of the
respective smoke generator's a\'eraoe opdell\
over the range of 0", through 80';. then the
lidar shall be considered Oul of ca!loroll,un
3.3.1.2 Screens. If the hdar.me..,urt'd
average opacity for each data run IS no:
within :::3% (full scale) of Ihe laborator\'
determined opacity for each respecllve
simulation screen target over the range of 0,
through 60%. then the lidar shall be
considered out of calibration.
3.3.2 Routine Verification Error. If the
lidar-measured average opacity for each
neutral density filter (Technique 1) or optical
generator selection (Techmque 2) IS nol
within :t:3% (full scale) of Ihe respecti\ e
laboratory calibration value then the !ldar
.hall be considered non-operational.
4. Performance/Design Specification for
Basic Lidar System.
4.1 Lidar Design SpecIfication. The
essential components of the basic hdar
system are a pulsed laser (transmltterl.
optical receiver. detector. signal processor.
recorder. and an aiming device thai IS used In
aiming the lidar transmitter and recPlver.
FIgure AM1-VU shows a functional block
diagram of 8 basic lidar system.
.'WHO CODE --
-------
53161
Federal Register I Vol. 46. Nc. 208 I Wednesday. October 28. 1981 I Rules and Regulations 53162
1------------,
Transmitted Light Pulse I PulSed I
(-, laser I
, ,
I Nauow Band Ophc.al filler I
, I
Backscalter Return Signal, O~hC" ,
- ) 'Rccc..,' ,
I I
I. I
tl- ~,:g~,,:. _1- - - - J
L - ~p~t~t'~I- - - - - - J
BilliNG CODE UiO-3I.C
..: ~ Performetnce F.\'dluahon Tests The
(JI', ~IN of a I1dar system shull 5uotPCl !Ouch a
la101r 5\ slf'M 10 Ihe" performance verification
",..~... de!lcfloed In Section 3 The annual
"'.,110" shall be performed for thr£>('
L,"PMiltc comrlt'te runs Bnd Ihf' results of
l'.H h ~houid be rerordf"d The requlremf'nls of
!-tt'Chon 33 1 musl be fulf.lled for each of the
Ihrf'(' rUM
Om.e the conditions of the annual
r,,!obrotlOn are fulfilled Ihe !odar sh.1I be
<"11!qf'clf'd 10 the roullnp venflcatlon for three
"1'PM..t! campipte runs Thf' requirements or
~er"on 3.3 2 must be fulfilled for each of the
Ihrt'P runs and the results ahould be recorded
T~w Administrator may requestlhat the
n'~ulll of thr performance e\'iiluallon be
submitted for review
5 Rcfrrences
Vt(SeO 5.9nill
F'gu,e AMI.VII
cr
I
Recorder
I
Fun."ono' 110.. Ora"om 0' 0 101" I,dor Srl10m
~.1 The Use of Lidar for Emissions SOl1rce
Opacity Determination. U S Environmental
Protection Apency, National Enforcement
InvestJ~allons Center, Denver. CO, EPA-330/
1-79-003-R. Arthur W. Dybdahl. Curren I
editIOn 11Io'TIS No. PB81-24661121.
~ 2 Fieid E,'aluation 01 Mobile Lidar for
the Measurement 01 Smoke Plume Opacity.
l1.S. Environmental Prolecllon A~ency.
r\atlonal Enforcement Investigelionl Cenler.
Drnver, CO. EPA/NEIC- T&-IZ8, February
1976
~.3 Remote Me.surement of Smoke Plume
Tronsmillance USinS Lid.r, C. S. Cook, G. W.
Bethke. W. D. Conner IEPA/RTP). Applied
OpllCS 11, p~ 1742. AupuSl1972.
~.4 Lidar Studies of St.ck Plumes In RUI'II1
and Urban Environments, EPA-6S0/4--7J-«12.
Oclober 1973.
256
~~ Americ.n National Standard for the
Safe Use of L..era ANSI Z 138.1-176, 8 March
1976
~.6 U.S. Ann\' Technic.l Manual TB MED
279, Control of tia..rds to Heallh from La.er
Radlouon, February 1969.
5.7 L..er In.tltute of America Leaer
S.fet\' Manu.1. 4th EdiUon.
~.8' U.s. Department of Heallh, Education
and Welfare. Resulations for the
Administration and Enlorcement of the
Rad,at,on Control for Heallh .nd S.fety Act
of 1968. Janu.r}' 1976.
S.9 La.er Safety Handbook. Alex Mallow,
Leo~ Chabot, Van Nostrand Reinhold Co..
1978
IFR Ooc 81-31:43 f.llPd IO-Z1~l, 845 .ml
.'LLINQ CODE &SIO-JI-M
-------
Federal Register I Vol. 47, No. 231 I Wednesday. December 1. 1982 I Rules and Regulations
54073
40 CFR Part 60
IAD-FRL-2228-71
Standards of Performance for New
Stationary Sources; Methods 6A and
68 for the Determination of So,
Moisture, and C02 Emissions From
Fossil Fuel Combustion Sources
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: Two reference methods
(Methods 6A and 6B) were proposed in
the Federal Register on January 26. 1981
(46 FR 8352). This action promulgates
the test methods for the determination
of SO.. moisture. and Co. emissions
from fossil fuel combustion sources as
acceptable procedures for compliance in
II 60.48 and 6O.47a of 40 CFR Part 60.
Subparts D and Da. respectively.
Revisions to U 60.48 and 6O.47a are
being made to make this section
consistent with use of the new test
methods.
EFFECTIVE DATE: December 1. 1982.
Under Section 307[b)(1) of the Clean
Air Act. judicial review of these new
test methods is available only by filing
of a petition for review in the U.S. Court
of Appeals for the District of Columbia
Circuit within 60 days of today's
publication of this rule. Under Section
307(b)(2) of the Clean Air Act. the
requirements that are the subject of
today's notice may not be challenged
later itn:ivil or criminal proceedings
brought by EPA to enforce these
requirements.
ADDRESSES: Summary of Comments and
Responses. The summary of comments
and responses for the proposed methods
may be obtained from the U.S. EPA
Library [MD-35). Research Triangle
Park. North Carolina 27711. telephone
number [919) 541-2777. Please refer to
"Summary of Comments and
Response&-Addition of Methods 6A
and 6B to Apppendix A of 40 CFR Part
257
-------
54074
Federal Register I Vol. 47. No. 231 I Wednesday, December t. 1982 I Rules and Regulations
60. EPA-4SO/3-8z-ms." The document
contains (1) a summary of the changes
made to the test methods since proposal
and (2) a summary of all the public
comments made on the proposed
specifications and the Administrator's
responses to the comments.
Docket. A docket, number A-OO-30,
containing information considered by
EPA in the development of the method.
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). West Tower Lobby.
Gallery 1, 401 M Street. S.W..
Washington, D.C. 20460. A reasonable
fee may be charged for copying.
FOR F1JRTHER INFORMATION CONTACT:
Roger T. Shigehara. Emission
Measurement Branch, Emission
Standards and Engineering Division
(MD-19). U.S. Environmental Protection
Agency, Rpsl'arch Triangle P.uk, North
Carolln" 27711. telephone (919) 541-
2237.
SUPPLEMENTARY INFORMATION:
Public Participation
Methods 6A and 6B were proposed
and published in the Federal Register on
Januray 26, 1981 (46 FR 8352). Public
comments were solicited at the time of
proposal. To provide interested persons
the opportunaty for oral presentation of
data, views or arguments concerning the
test methods. a public hearing was
scheduled for February 19. 1981.
beginning at 9:00 a.m. The hearing was
not held because no one requested to
speak. The public comment period was
from January 26, 1981 to March 27. 1981.
Eleven comment letters were received
concerning issues relative to the
proposed test methods. The comment.
ha ve been carefully considered; and.
where determined to be appropriate by
the Administrator. changes have been
made in the proposed methods.
Significant Comment. and Cbange. to
The Proposed Test Method.
Comments on the proposed test
methods were received for industry.
Federal agencies, State air pollution
cuntrol agencies. trade associations, and
equl;>ment manufactUIers. A detailed
dlsc':ssion of these comments and
resr :ses can be found in the separate
doc-L ent mentioned in the
ADDt SSSES section of this preamble.
The se nmary of comments and
respc,nses serves as a basis for the
re\ iSlDns which have been made to the
test methods between proposal and
promulgation. The major comments and
"',pollses are summarized in this
p"...mble. Must of the commenlletters
cunt,lIned multiple comments. The
comments and responses have been
divided into the following areas.
Accuracy
One commenter had several question.
about the accuracy achievable with
Methods 6A and 68. Specifically. the
commenter noted experience with test
data that were in error due to Invalid
diluent data. The commenter .tated
further that the F-factor calculation
would also be invalid due to the
inaccurate diluent data. Another
commenter questioned the proposed use
of a method that could not be qualified
or certified as could 8 continuous
emission monitoring system (CEMS). A
lack of data supporting an evaluation of
the precision and accUIacy of Methods
6A and 8B was noted by two other
commenters.
The EPA has conducted several field
studies using Methods 6A and 6B, and
the reports are listed in the bibliography
of tbe methods. The reports are
available upon request. The results
show the methods to be accurate and
comparable to the results of Methods 6
and 3 in determining So, emission rates.
The difficulties encountered in
accUIately measUIing diluent data as
mentioned by the one commenter can
usually be traced to the testers and the
testers' failUIe to follow adequately the
quality assurance procedures in the
method. Additionally. these comment.
seemed to be directed at Method 3.
rather than Methods 6A Qr 68. The Co,
meaSUIement procedUIes used in
Methods 6A and 6B are based on the
American Society for Testing and
Materials (ASTM) standard method D
3178 commonly used by the utility
industry and others. In response to the
comment concerning certification of
Method 68 as a CEMS. the Agency feel.
that the method can be certified as a
CEMS, if desired; and. with adequate
quality aSSUIance and quality control
meaSUIes, can be used in place of an
instrumental CEMS dUIing periods of
CEMS breakdown. as required by the
applicable regulation.
Applicability
One commenter noted that the use of
Method SA without the dry gas meter
should be specified only for fossil fuel
combustion SOUIces. Two commenters
asked about the intention of the Agency
in use of Method 6B in place of CEMS
and recommended that its applicability
be extended to include Method 6B as an
acceptable alternative to CEMS.
Another commenter said that Method 6B
could not be applied to stack! or ducts
with significant. negative static pressure
due to the possibility of reverse flow
through the sample train.
258
Methods 6A and 68 state clearly that
they are ap!:,licable only for fossil fuel
combustion SOUIces in either
configuration. that is. with or without
the'dry gas meter. The Agency considers
Method 68. an appropriate method for
providing long-term emission data
during periods of CEMS breakdown. The
Agency is also considering use of
Method 68 as an alternative to CEMS
for fossil fu~l combustion sources. but
that determination is not final. The
application to specific types of stacks or
ducts must be determined on a case~by-
I;ase basia. Use of probe valves In
connection with the sample timer or a
switch to continuous sampling could
resolve the problem of negative stack
pressure.
Technical Changes to Meth(Xis
Several commenters recommended
the use of heated probes. an isopropanol
impinger. additional ascarite absorbers.
larger volume sampling vessels, and
higher peroxide concentrations.
The Agency agrees that some of these
changes are valid and useful. A beated
probe requirement has been added to
botk methods. as well as modification to
the ascarite absorber design. An
Isopropanol impinger has been included
in Method 6A. but. due to possible
interferences with the
CO. measurement, the isopropanol
Impinger is not Included in Method 6B.
The methods also Include the use of
hydrogen peroxide concentrations up 10
10 percent over the 3 percent included in
the proposal. The methods do not
recommend the use of larger volume
sampling equipment. such as is used
with Method 8. The Agency feels that
the cost of the expendable materials
should be considered in determining the
sample volume and. in addition. feel.
that the accUIacy of the method is not
impaired by the use of lower volume
flow rate equipment. The use of such
equipment or some of the other
alternatives is not prohibited by the
methods. The tester may use any of
several alternatives in equipment.
operating parameters. or techniques and
remain within the restrictions of the
methods providing accurate and precise
results. .
Docket
The docket is an organized and
complete file of all the information
considered by EPA in the development
of this ruIemaking. The docket is a
dynamic file. since material is added
throughout the rule making development.
The docketing system is intended to
allow members of the public and
industries involved to identify and
-------
Federal Register I Vol. 47. No. 231 I Wednesday. December 1. 1982 I Rules and Regulations
54075
locale documents so that they can
intelligently and eCfectively participate
in the rulemaking process. Along with
the statement of basis and purpose of
the proposed and promulgated test
methods'and EPA responses to
significant comments. the contents oC
the docket will serve as the record in
case of judicial review [Section
307(d)(7)(A)j.
Miscellaneous
This rulemaking does not impose any
additional emission measurement
requirements on facilities affected by
this rulemaking. Rather. this rulemaking
provides alternative test"methods which
may be used by the affected facilities. If
future standards impose emission
measurement requirements. the impacts
of the alternative test methods
promulgated today will be evaluated
during development of these standards.
Under Executive Order 12291. EPA
must judge whether a regulation is
"major" and there Core subject to Ihe
requirement of a regulatory impact
analysis. This regulation is not major
because it will not have an annual effect
on the economy of $100 million or more;
it will not result in a major increase in
costs or prices; and there will be no
significant adverse effects on
competition. employment. investment.
productivily. innovation. or on the
ability of U.S.-based enterprises to
compete with foreign-based enterprises
in domestic or export markets.
Pursuant to the provisions oC 5 U.S.C.
605(bl. I hereby certify that the attached
rule will not have a significant economic
impact on a substantial number of small
entities.
This rule was submitted to the Office
of Management and Budget under E.O.
12291.
List of Subjects in 40 eFR Part 60
Air pollution control. Aluminum.
Ammonium sulfate plants. Cement
industry. Coal. Copper. Electric power
plants. Glass and glass products. Grains.
Intergovernmental relations. Iron. Lead.
Metals. Motor vehicles. Nitric acid
planls. Paper and paper products
i~dustry. Petroleum. Phosphate. Sewage
disposal. Steel. Sulfuric acid plants.
Waste treatment and disposal. Zinc.
Thi8 final rule making is issued under
Ihe authority of Sections 111. 114. and
301(a) of the Clean Air Act. a8 amended
(42 U.S.C. 7411. 7414. and 7601(a)].
Dated: November 22. 1982.
Anne M. Gorsuch.
Administrotor.
PART60-[AMENDEDI
Seclions 60.46. 6O.47a. and Appendix
A of 40 CFR Part 60 are amended as
follows:
1. By revising ~ 6O.46(a)(4] as Collows:
f 60.46 Test methods and procedures.
(a). . .
(4) Method 6 for concentration of SO..
Method 6A may be used whenever
methods 6 and 3 data are used to
determine the SO. emission rate in ng/l.
and
2. By revising 160.47a{h)(1] as follows:
f 60.47a Emission monitoring.
(h)' . .
(1) Reference Methods 3. 6. and 7. as
applicable. are used. Method 6B may be
used whenever Methods 6 and 3 data
are required to detennine the SO.
emission rale in ng/l. The sampling
location{s] are the same as those
specified for the continuous emission
monitoring system.
3. By adding Methods 6A and 6B 10
Appendix A of 40 crn Part 60 to read as
follows:
Appendix A-Relerence Test Methods
.
Metbod 6A-Detennination of Sulfur
Dioxide. Moisture. 8nd Carbon Dioxide
Emissions From Fossil Fuel Combustion
Sources
1. Applicability and Principle
1.1 Applicability. This method applies to
the determination of sulfur dioxide (SO,)
emissions from Cossil fuel combustion sources
in lenns of concentration (mg/m'J and in
259
terms 01 emission rate (ng/IJ and to the
determination of carbon dloxid.e (CO,)
concentralion (percent). Moisture, If deSlrl'd.
may also be determined by this method.
The minimum detectable limit. the uppPr
I,mit. and the interferences of the method lor
the measurement 01 SO, are the same as lor
Method 6. For a 20-liler sample. the method
has. precision of 0.5 percent CO. for
concentrations between 2.5 and 2S percent
CO. and 1.0 percent moisture for moisture
concentrations greater than S percent.
1.2 Principle. The principle of sample
collection IS the same 8S for Method 6 exu'pt
that moisture and CO. are collected in
addltian to SO, in the same sampling train
Moisture and CO. fractions are determlnpd
gravimetrically.
2. Apparatus
2.1 Sampling. The sampling train is sho\'o n
in Figure 6A-1: the equipment required is the
same as for Method 6, Section 2.1. except as
specifIed below:
2.1.1 SO, Absorbers. Two 30.ml mid~et
impingers with a 1-mm restricted tip dnd two
30.ml midget bubblers with an unrcstricted
tip. Other types of impingers and bubblers,
such as Mae West bubblers. may be used
wIth proper attention to reagent volumes and
levels.
2.1.2 CO, Absorber. A sealable glass or
plastic cylinder or bottle with an inside
dIameter between 30 and 90 mm and a length
between 125 and 250 mm and with
appropriate connections at both ends. Notc:
For appllf.atlOns downstream of wet
scrubbers. a heated out-of-stack filter (either
borosIlicate glass wool or glass f,ber mat) '"
necessary. The probe and filter should bc
heated to alleast 20. C above the source
temperature. but nol greater than 120. C.
22 Sample Recovery and Analysis The
equipment needed for sample recovery and
analys.. IS the Sdme as required for Ml'Ihod
6. In addilion. a balance 10 measure wlth,n
0.05 g IS needed for analysis.
3. Reagen/s
Unless otherwise indicated. all reagents
must confonn to the specifications
established by the committee on analytical
reagents of the American Chemical Society.
Where such speCillcatlons are nol avalldble.
use the best avaIlable grade.
3.1 Sampling. The reagents required for
sampling are the same as specified In ~lethod
6. In addition. the following reagents are
required:
BILLING CODE S560-~1I
-------
THERMOMETER
HEATED PROBE WUCK WALL
tEND PACKED WITH QUARTZ
OR 'YREX WOOU
N)
C'I
o
8IWNG CODE ...-.0
i
~
MIDGIT IMPINGERS
MIDGET IUIILER~
eOZAIIORIER
PUMP
SURGE TANK
Figure SA-1. Sampling train.
~
o
CiI
"IS
It
It
!.
1
Iii"
18
..
--
<
~
..
.:'I
Z
!J
N
<0)
...
--
:E
':'=
C
It
n
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Federal Register I Vo\. 47. No. 231 I Wednesday. December 1. 1982 / Rules and Regulations
54077
311 Oriente. Anhydrous calcium sulfate
((..50,1 desiccant. 8 mesh. (Do not use silica
gel or similar desiccant in this application.)
3 1.2 Ascarile or Ascarile II. Sodium
h} dro~ide coated asbestos or silica for
aLsorption of CO.. 8 to 20 mesh.
3.2 Sample Recovery and Analysis. The
r""gents needed for sample recovery and
analysis are the same as for Method 6.
Sections 3.2 and 3.3. respectively.
4. Procedure
4.1 Sampling.
4.1.1 Preparation of Collection Train.
MI!asure 15 ml of 80 percent isopropanol ihto
the firsl midget bubbler and 15 ml of 3
percent hydrogen peroxide into each of the
first two midget impingers as descnbed an
Method 6. Insert the glass wool into the top of
the isopropanol bubbler as .hown in Figure
6A-l. Into the second midget bubbler. the
fourth vessel an the train. place about 25 g of
dnente. Clean the outSIdes of the bubblers
and Impingers and weigh lat room
temperature. ..20' C) 10 the nearest O.lg.
WeIgh the four "essels simultaneously and
record Ihis initial mass.
With one end of the CO. absorber sealed.
place glass wool in the end filling the cylinder
aboull cm deep. Place about 150 II of ascante
261
in the cylander on top of the glass wool dnd
f,lI the remallllngspaceinthecylinder...th
glass wool. Assemble the cylinder as sho,", n
in Figure 6A-2. With Ihe cylinder in a
honzontal posllion. rotate It around the
honzontal axIS. The ascarite should rem."n ,n
posilion during the rota lion and no open
spaces or channels should be formed If
necessary. pack more glass wool into Ih..
cylinder to make the ascarlte more stable
W,lh the outside of the cylinder cleaned.
we'gh (al room temperature. .. 20' C) to the
nearest 0 1 g. Record this anitial mass.
BILLING CODE 8560-50-11
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54078
Federal Register I Vol. 47, No. 231 I Wednesday, December t. 1982 I Rule. and Regulation.
RUlIER STOPPER
Figure 6A.2. C02 absorber.
BILLING COOl .~so-c
262
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Federal Regi5ter I Vol. 47. No. 231 I Wednesd'lY. Der.emhp.r 1. 1982 I Rules and ReKulalions
54079
Assemble the Irain as sho..o in Figure 6A-
1, Adjust the ptobe heater to atemperdture
,ufficienlto prevent ..aler condensahoo.
Pldce crushed ice and water around the
Impinge... and bubble.... Mounlthe co,
..bsorber outlide the water balh in a verlical
nuw pOlition with sample gal inlet al the
bollom. Flexible tubing. e.g.. Tygon. may be
used to conneclthe drierite bubblcr 10 the
Co. ablorber. A lecond. ImaUer ascarite
Co. dblorber may be added in line
downstream of the primary Co. ablorber as
.. brcakthrough indicator. if 10 desircd by the
,,,.Icr. As carile tuml white ..hen CO. il
.1 bsorbed.
4.1.2 Lealr.-OIeck Procedure aDd Sample
Collection. Tbe leak..:h",,1r. procedure and
,ample colleclioo procedure are lbe same as
specified in Method 6. Sections 4.1.2 and
4.1,3. relpectively.
4.2. Sample Recovery.
4.2.1 Moisture Measuremen!. Dilconnect
the ilopropanol bubbler. the peroxide
impingerll. and the drierite bubbl.... from Ihe
sample train. Allo.. lime (aboul10 minulell
ror them to reach room temperature. clean the
outside.. and then weigh them
simultaneoully in the same manne«' al in
Sectioo 4.1.1. Record Ihil linal mall.
4.2.2 """",ide Solution. Dilcard the
':ontentl of the ilopropanol bubbl.... and pour
thc conlentl of the midget impinge... ialo a
leak.free polyethylene bollie for shipping.
Rinse the two midgel impinge... and
"onnechng tubel wHh deionized distilled
water. and add the walhings 10 the same
sloraMe conlsiner.
4.2.3 Co. Ab80rber. Allow the co.
,.b90rber 10 wanD to room temperalure (aboul
10 minulel). clean the outaide. and weigh to
Ihe nearell 0.1 gin Ihe same manner as ia
Section 4.L1. Record this final mas. and
discard the uled ascarila.
4.3 Sample Analysll. The sample analYlb
procedure for SO, il Ihe lame 81 specilied in
Method 8. Section 4.3.
.'i. Calibration
The calibrationl and c8ecka are the &am8
as required in Melhot! 6. Seclion 5.
/I. Calculation.
ed"'" out calc..latloa8. relaining alleall
une exa decimal figure beyond thaI of the
acquired dala. Rauod off ligures afler final
"..Iculatioal. The calculalioD8. nomenclature.
and procedurel are the same al specified in
Method 8 with the addition of Ihe following:
6.1 Nomenclalure
C'J'lo=Concentralion of moisl\lre. perceat
e. ." = Concenlraliell of co.. dry basi..
percent.
m., = lnilial maSI of peroxide impingers and
drierila bubbler. II-
m.., = Final mall of peroxide impinge... and
drierile bubbler. a-
m., = InitlRI mass of ascanle bubbler. g.
m.,=Final man of ascarlte bubbler. g.
'Co,(stdJ = Standard equivalenl voluma 01
Co. collected. dry balil. M'.
6.2 co, VoIlIIIIt! CoBected. Corrected to
Standard ConditionL
V.....,.. = 5.48'7 X 1O-41m..-m.J (Eq. &A-11
6.3 MoitIIure V o\uw!e CoIIecie41. Con 8. with the add.ttion of the roll"" Ing:
6.2 Stanley. Jon and P.R. WestlllL An
Alremate Melhod ror Stack Gas Moisture
Determination. Source Evaluallon Society
Newsletter Vol. 3. No.4. November 1!r.8,
6.3 Whittle. Richard N. and P,R. Westhn.
Air Pollution Test Report: De...elopmcnl and
Evaluation of an Intermittent Integrated so,l
Co. Emission Sampling ProcedlH'e.
Environmental Protection Agency. Emission
Standard and Engineering Di,ismn. Fmissmn
Mell8uretnent Branch. Research Triangle
p.m.. North Carolina. December 1979. 14
pag"".
Method IB-Delennination of Sulfur Dioxide
and Carbon Dioxide Dally A ,'erage Emi"ions
From Fossil Fuel Combultioa Source8
,. Applu;nb,bty and Principle
1.1 Appljcability. Thi. method IIpphl!s 10
the determination of .ulfur dioxide ISO.)
emliliona from combulHon lources in h~nn.
of concentration (mg/m') and emission I"'dle
[ngm. and for the determination of Cdrboa
dioxide (CO,) concentration (percent) I)n a
dally (24 hours) basil.
The minimum detectable limit. upper Ii mil.
and the interferences for SO, measll,-empnts
a." the same as ror Method 6. For a 2f).!itp.r
sdmple. the method has a precision of 0,5
percent CO, for concentrations between 2.5
and 25 percenl CO,.
1.2 Pnnciple. A gill sample is extractpd
from Ihe sampling poinl in the stdck
intermittently ov.... . 24-ftour or olher
spKilied time period. Sampli"l may .Iso ""
conducled continuoully if the appal"'dtus and
procedure are modilied (see Ihe note in
Seclion 4.1.1). The SO, and Co. are separatP.
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54080
Federal Register I Vol. 47, No. 231 I Wednesday. December 1, 1982 I Rules and Regulations
Method 6A regarding filter Iypes and probe
heat specificalions.
3. Reagen/5
All reagents for samphng and analysis are
the Same as described," Method liA. Section
3. ",cept that isopropanol.. not used for
sampllr.g The hydrogen pero"de absorbong
sulullon sball be diluted to no I..s than 6
percent by volume. instead of 3 percenl as
specified," Method 6.
4 Pro( eduN!
4 1 Sampling.
4 1.1 Preparalion of Collection Train.
Preparation of the sample tra," IS the same 81
described in Method liA. Seclion 4 1.4. with
the add. lion of the follow,"g:
1 he sampl,"g Ira," .. assembled as sbown
In Figure liA-l. e.cept the isuprnpanol
LuLLler IS nol ,"cluded. The probe musl be
h"dled 10 a temp
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TECHNICAL REPORT DATA
(Please read IRurucrions on the rel'erse before completing)
1. REPORT NO. 12. 3. RECIPIENT'S ACCESSIOilf'NO
EPA 450/2-83-001
4. TITLE AND SUBTITLE 5. REPORT DATE
APTI Course 474 Januarv 1933
Continuous Emission Monitoring 6. PERFORMING ORGANIZATION CODE
Regulatory Documents
7. AUTHOR(S) B. PERFORMING ORGANIZATION REPORT NO.
James A. Jahnke, Ph.D.
9, PERFORMING OR"ANIZATION NAME AND ADDRESS 10. PR(JGRAM ELEMENT NO.
Northrop Services, Inc. B18A2C
P.O. Box 12313 11. CONTRACT/GRANT NO.
Research Trian~le Park, NC 27709 68-02-2374
12. SPONSORING AGENCY NAME AND ADDRESS 13. TYPE OF REPORT AND PERIOD COVERED
U.S. Environmental Protection Agency Student Naterial:--; 1l)7,)-I':IH2
Manpower and Technical Information Branch 14. SPONSORING AGENCY CODE
Research Triangle Park, NC 27711 EPi\-OAt\R-OAQPS
15, SUPPLEMENTARY NOTES
Project officer for this workbook is R. E. Townsend, EPA-ERC, HD 20,
Research Triangle Park, NC 27711
16, ABSTRACT
This collection of regulatory documents is to be used in conj lInc t ion with
presentations of Air Pollution Training Institute Course 474, "Continuous emission
Monitoring". This publication contains selections from the Code of Fec1era L
Regulations and Federal Register publications dealing with continuous source
monitoring. Selections from the Federal Register cover the period Octoher n, 1°7')
to December 1, 1982.
This publication is intended as reference material to supplement the COllrsC'
student manual (EPA 625/6-79-005) and the student workbook (EPA 450/2-82-() 17) .
17, KEY WORDS AND DOCUMENT ANALYSIS
b.IDENTIFIERS/OPEN ENDED TERMS ,--
a. DESCRIPTORS c. COSATI held/Group
Air Pollution Training Source Honitoring 14B
Neasurement 14D
Continuous Emission Monitoring
Gas Samplin~/Measurement
1'3. DISTRIBUTION STATEMENT 19. SECURITY CLASS (This Report/ 21 NO OF PAGES
National Technical Information Service unclassified :271
52R5 Port Royal Road 20. SECURITY CLASS (This page) 22. PRICE
Springfield, VA 22161 unclassified
EPA Form 2220.1 (9.73)
265
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