oEPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Wangle Park NC 27711
EPA-450/3-79-Q21
June 1979
PB-298510
Air
Electric Utility Steam
Generating Units
Background Information
for Promulgated
Emission Standards
EIS
REPRODUCED BY
NATIONAL TKHNlCAl
INFORMATION SERVICE
U.S. DEPARTMENT OF COWMEKE
SPBINSFIEU3, Vfc 221S1
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7, AU I'HOHiS!
TECHNICAL REPORT DATA
(Hcaie read ftixtnicriom on ikf reverse hzfort comptertrrsj
4. TITll: ANO SUBTITLE
Electric Utility Steam Generating Units-Background
Information for Promulgated Emission Standards
S. PERFORMING QHCANtZATIOf* RSPOHT NO,
. i'SHFOniMING ORGANIZATION NAME AND ADDRESS
U. S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
li. ;
DAA for Air Quality Planning and Standards
Office of Air, Noise and Radiation
U. S, Environmental Protection Agency
Research Triangle Park, North Carolina 27711
3. HCC1PI
S. REPORT DATE
June 1979
fi. PERFORMING OBGANIZATrON CODS
,o_ PROGRAM ELEMENT wo.
TV. CONTRACT/en ANT NOT
13, TYPE OF REPORT AND PfiBJOD COV6RSD
»4. SPONSORING AGENCY COOS
EPA/200/04
Revised standards of performance for the control of oarticulate matter, sulfur oxides,
and nitrogen oxides emissions from electric utility steam generating units were'
proposed on September 19, 1978. The proposed standards were supported by four separate
Background Information Documents (EPA-45Q/2-78-QGSa» EPA-450/2-78-006a, EPA-450/2-78-007
a, and EPA 450/2-78-007a-l.. •-•-••
L
116, Abstract
Standards of performance for the control of Darticulate matter, sulfur dioxide,-.and .
nitrogen oxides emissions from electric utility steam generating units have been adopted
under the authority of section 111 of the Clean Air Act. These standards aoply only.to
electric utility steam generating units capable of combusting more than 73 -megawatts
(250 million Btu/hr) heat input of fossil fuel and for which construction or modifica-
tion began after September 18, 1078. This document contains background information,
public comments, additional data collected since orooosa.1, and EIS. ". .
J.
D
KEY WORDS AND DOCUMiNT ANALYSIS
= SCniHTORS Ib.lDENTIFlcRS/OPSN ENOEDTERMS
Air pollution Parti cul ate matter
Pollution control Subpart Da
Standards of performance
Electric utility power olants
Steam generating units
Nitrogen oxides
Sulfur dioxide
-.:. i : r; i H n ' , ;T : ON K TAT » :,*:-. N ';
Unlimited
Air Pollution Control
1D, EECUHiTY CLASS {This Kf port)
Unclassified
2O. Sf=CUSlTY Cl.AS"* jnitpagtj
Unclassified
c. COSATI Field/Group
13B
21. NO. OF PACES
a U./
22, PRICE //•//-"
i-ri Z2V3-1 1 '->•"
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EPA-450/3-79-021
Electric Utility Steam
Generating Units
Background Information for
Promulgated Emission Standards
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
June 1979
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This report has been reviewed by the Emission Standards and
Engineering Division of the Office of Air Quality Planning and
Standards, EPA, and approved for publication. Mention of
trade names or commercial products is not intended to constitute
endorsement or recommendation for use. Copies of this report
are available through the Library Services Office (MD-35),
U. S. Environmental Protection Agency, Research Triangle Park,
N. C. 27711, or from National Technical Information Services,
5285 Port Royal Road, Springfield, Virginia 22161.
Publication No. EPA-450/3-79-Q21
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Background Information
and Final
Environmental Impact Statement
for
Electric Utility Steam Generating Units
Type of Action: Administrative
Prepared by:
.7 «
Don R. Goodwill (Date)
Director, Emission Standards and Engineering Division
Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Approved by:
David G. Hawkins
Assistant Administrator for Air, Noise and Radiation
Environmental Protection Agency
401< M Street, S.W.
Washington, 0. C. 20460
Final Statement Submitted to EPA's -
Office of Federal Activities Review on
Additional copies may be obtained at;
Environmental Protection Agency Library (MD-35)
Research Triangle Park, North Carolina 27711
This document may be reviewed at:
Central Docket Section (A-130J
Room 2903B, Waterside Mall
Environmental Protection Agency
401 M Street, S.W.
Washington, D. C. 20460
(Date)
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TABLE OF CONTENTS
Chapter Page
1. BACKGROUND - ' 1-1
2. SUMMARY OF PUBLIC HEARING AND COMMENTS 2-1
2.1 CQNMENTERS AND PUBLIC HEARING SPEAKERS 2-1
2.2 ADMINISTRATIVE AND PROCEDURAL ACTIONS 2-61
2.3 AFFECTED FACILITY 2-64
2.3.1 60.40a Applicability and Designation of
Affected Facility z"64
. General Comments on Applicability 2-64
. Combined Cycle Facilities 2-65
. Cogeneration Facilities 2-66
. Resource Recovery Facilities 2-68
. Commenced Construction 2-70
. Modification 2-72
2.3.2 60,41 a Definitions 2-74
. Electric Utility Steam Generating Unit 2-74
. Utility Company 2-75
. System Capacity ' 2-76
. System Emergency Reserves 2-77
, Available System Capacity 2_7g
. Spinning Reserve ' ~ 79
. Emergency Condition 2-80
2.3.3 Special Issues 2-83
. Anthracite Coal 2-83
Noncontinental Areas 2-87
. Alaskan Coal - 9-88
. Emerging Technology , 2-90
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TABLE OF CONTENTS
(continued)
Chapter Page
2.4 EMISSION LIMITS 2-93
2.4.1 60.42a Standard for Particulate Matter 2-93
. General Comments on Particulates 2-93
Particulate Emission Limit 2-94
. Best System of Emission Reduction for 2-99
Particulates
. Adequacy of the Particulate Data Base 2-106
. Averaging Time for Participates 2-111
. Particulate Control in the Presence of
S02 and/or NOX 2-112
. Opacity Standard for Participates 2-113
2.4.2 60.43a Standard for Sulfur Dioxide 2-116
. Sulfur Dioxide Emission Limit 2-116
. Best System of Emission Reduction for
Sulfur Dioxide 2"124
. Adequacy of the Sulfur Dioxide Data Base 2-131
. Averaging Time for Sulfur Dioxide 2-140
. Sulfur Removal Credit 2-143
2.4.3 60.44a Standard for Nitrogen Oxides 2-146
. Nitrogen Oxides Emission Limit 2-146
, Best System of Emission Reduction for
Nitrogen Oxides 2-149
. Adequacy of the Nitrogen Oxides Data Base 2-153
, Averaging Time for Nitrogen Oxides 2-155
. Relationship of Nitrogen Oxides with
Other Pollutants 2-156
, Nitrogen Oxide Cost Analyses 2-157
. Nitrogen Oxide Safety Issues 2-158
x/
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TABLE OF CONTENTS
(continued)
Chapter Page
2.5 TESTING, MONITORING, AND REPORTING 2-159
2.5.1 60.46a Compliance Provisions 2-159
. Compliance Testing 2-159
. Startup, Shutdown and Emergency Bypass 2-160
2.5.2 60.47a Emission Monitoring 2-163
. General Comments on Emission Monitoring 2-163
. Monitoring Instrument Accuracy 2-171
. Monitoring Instrument Reliability 2-172
. Continuous Monitoring 2-174
. Backup Manual Monitoring 2-177
2.5,3 60.48a Compliance Determination Procedures
and Methods 2-180
2.5.4 60.49a Reporting Requirements 2-183
• 2.6 APPENDIX A, REFERENCE METHODS 2-185
2.7 ECONOMIC IMPACTS 2-189
. Cost to Consumer 2-189
. Cost to Other Industries 2-197
. Measures of Economic Impact 2-202
. Great Lakes Transportation 2-203
2.8 ENVIRONMENTAL IMPACTS 2-204
. General Comments on Environmental Impacts 2-204
. Sludge 2-208
. Acid Rain 2-210
. Ambient Air Quality 2-211
. Prevention of Significant Deterioration
(PSD) Program , 2-212
v/
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TABLE OF CONTENTS
(continued)
Chapter Page
. Water 2-214
. Other Legislation 2-215
2.9 ENERGY IMPACTS 2-217
2.10 HEALTH EFFECTS 2-220
2.11 GENERAL COMMENTS ON ENTIRE STANDARD 2-222
2.12 COMMENTS NOT ADDRESSING THE PROPOSED STANDARD 2-228
2.13 COMMENTS DUPLICATING PREVIOUS SUBMISSIONS 2-229
3. SULFUR DIOXIDE 3-1
3.1 INTRODUCTION 3-1
3i2 PERFORMANCE TEST REPORT A 3-2
3.2.1 Description of Test Sites 3-4
3.2.1.1 Conesville Unit No. 5, Columbus
and Southern Ohio Electric Company 3-4
3.2.1.2 Shawnee FGD Prototypes, Tennessee
Valley Authority 3-6
3.2.1.3 Mitchell No. 11, Northern Indiana
Public Service Company 3-7
3.2.2 Data Gathering Systems 3-10
3.2.2.1 Conesville No. 5 Columbus and
Southern Ohio Electric Company 3-10
3.2.2.2 Shawnee IDA and 10B, Tennessee
Valley Authority 3-13
3.2.2.3 Mitchell No. 11, Northern Indiana
Public Service Company 3-15
3.2.3 Data Reduction Procedures 3-15
3.2.4 Data Analysis 3-22
3.2.4.1 Data Calculation Assumptions 3-22
3.2.4.2 Data Availability 3-22
3.2.4.3 Statistical Analyses 3-24
3.2.5 Conclusions ^ 3-37
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TABLE OF CONTENTS
(continued)
Chapter . Page
3.3 PERFORMANCE TEST REPORT B 3-38
3.3.1 Description of Test Sites 3-39
3.3.1.1 Shawnee FGD Prototypes, Tennessee
Valley Authority 3-39
3.3.1.2 Lawrence Unit No. 4, Kansas Power
and Light Company 3-41
3.3.2 Data Gathering Systems 3-43
3.3.2.1 Shawnee FGD Prototypes, Tennessee
Valley Authority 3-43
3.3.2.2 Lawrence Unit No. 4, Kansas Power
and Light Company 3-44
3.3.3 Data Reduction Procedures 3-46
3.3.4 Data Analysis 3-50
3,3.4.1 Data Calculation Assumptions 3-50
3.3.4.2 Data Availability 3-50
3.3.4.3 Statistical Analyses 3-52
3.3.5 Conclusions 3-59
3.4 DRY S02 CONTROL 3-60
3.4.1 Introduction 3-61
3.4.2 Pilot Scale Testing 3-62
3.4.3 Economics 3-66
3.4.4 Environmental and Energy Impacts 3-73
3.4.5 References 3-76
4. PARTICULATE 4-1
4.1 INTRODUCTION 4-1
4.2 LARGE BAGHOUSE CONTROL SYSTEMS 4-1
4.3 PERFORMANCE TESTING - ACID MIST 4-2
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TABLE OF CONTENTS
(continued)
Chapter Page
5. NITROGEN OXIDES 5-1
5.1 INTRODUCTION 5-1
5.2 INFORMATION RECEIVED AFTER PROPOSAL 5-1
6. . ENVIRONMENTAL IMPACT STATEMENT SUMMARY 6-1
6.1 INTRODUCTION 6-1
6.2 PUBLIC COMMENTS 6-2
6,3 ENVIRONMENTAL IMPACTS 6-2
6.4 SUMMARY OF IMPACTS FOR FINAL ALTERNATIVES CONSIDERED 6-4
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1. BACKGROUND
In December 1971, under section 111 of the Clean Air Act, EPA
promulgated standards of performance to limit emissions of SC^,
participate 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 SOg, participate matter, and
NO continue to be a national problem. In 1976, steam electric
X
generating units contributed 24 percent of the participate matter,
65 percent of the S09» and 29 percent of the NO emissions on a
£> if*
national basis,
EPA was petitioned on August 6, 1976, by the Sierra Club and
the Oljato and Red Mesa Chapters of the Navaho Tribe to revise the
SOp standard so as to require a 90 percent reduction in SOo emissions
from all new coal-fired power plants. The petition claimed that advances
in technology since 1971 justified a revision of the standard. As a
result of the petition, EPA agreed to investigate the matter thoroughly.
On January 27, 1977 (42 FR 5121), EPA announced that it had initiated a
study to review the technological, economic, and other factors needed to
determine to what extent the S02 standard for fossil-fuel-fired steam
generators should be revised.
1-1
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On August 7, 1977, President Carter signed into law the Clean
Air Act Amendments of 1977. The provisions under section m(b}(6)
of the Act, as amended, required EPA to revise the standards of
performance for fossil-fuel-fired electric utility steam generators
within 1 year after enactment.
After the Sierra Club petition of August 1976, EPA initiated
studies to review the advancement made on pollution control systems
at power plants. These studies were continued following the amend-
ment of the Clean Air Act. In order to meet the schedule established
by the Act, a preliminary assessment of the ongoing studies was made
in late 1977. A National Air Pollution Control Techniques Advisory .
Committee meeting was held on December 13 and 14, 1977, to present
EPA preliminary data. The meeting was open to the public and comments
were solicited.
The Clean Air Act Amendments of 1977 required the standards to
be revised by August 7, 1978. When it appeared that EPA would not
meet this schedule, the Sierra Club filed a complaint on July 14,
1978, with the U. S. District Court for the District of Columbia
requesting injunctive relief to require, among other things, that
EPA propose the revised standards by August 7, 1978. A consent
order was developed ind issued by the court requiring the EPA
Administrator to {!) deliver the proposal package to the office of
the FEDERAL REGISTER by September 12, 1978, and (2) promulgate the
final standards within 6 months after proposal (i.e., by March 19,
1979).
1-2
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The Administrator delivered the proposal package to the office
Of the FEDERAL REGISTER by September 12, 1978, and the proposed
regulations were published September 19, 1978 (43 FR 42154). Following
the proposal EPA initiated additional testing to assist in resolving
a number of technical issues raised during the proposal. EPA also
contacted other sources of information to assist in resolution of
these issues. Following proposal EPA also initiated additional
computer analyses of the impact of various alternative standards.
Public comments on the proposal were requested by December 15,
and a public hearing was held December 12 and 13, the record of which
was held open until January 15, 1979. More than 700 comment letters
were received on the proposal. The comments were carefully considerd,
however the issues could not be sufficiently evaluated in time to
promulgate the standards by March 19, 1979. On that date EPA
requested of the Court, and was granted, an extension whereby the
Administrator would sign and deliver the final standards to the
FEDERAL REGISTER for publication on or before June 1, 1979.
This document represents a summary of the comments received,
technical data collected since proposal, and an EIS summary which contains
a cross-reference to other documentation used in development of the
final standards.
1-3
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2.0 SUMMARY OF PUBLIC HEARING AND COMMENTS
2.1 Cotamenters and Public Hearing Speakers
Table 2-1 presents a listing of persons submitting written
comment on the proposed standard, Also shown is the EPA docket
number assigned to each comment and the organi2ational affiliation
of each commenter. Table 2-11 presents a listing of persons who
presented testimony at the public hearing and Table 2-III presents
a listing of official written comments from other federal organiza-
tions. Both of these listings also show the assigned EPA docket
numbers.
2-1
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TABLE 2-1
LIST OF PERSONS SUBMITTING WRITTEN COMMENTS
No. Docket No. Gommenters
1 D~-L H. S. King
(U. S. Resident)
2 D-2 J. W. Kellog
OJ. S. Resident)
3 D-3 Alvin P, Fentoti
(U. S. Resident)
4 D-4 Mrs. Norman Jackson
(U. S. Resident)
5 D-5 Paul C. Williams
(U. S. Resident)
6 D-6 Alice C. Grant
(U. S. Resident)
7 D-7 Mr. and Mrs. Kenneth Bell
(U. S, Resident)
8 D-8 Ray A. Arditi
(U. S. Resident)
9 D-9 Verlyn Marth
(U. S. Resident)
10 D-10 Vallerie J. Prime
(Citizens United for
Responsible Energy)
11 D-14 Bernard L. Coffindaffer
(Craigsville Distributing
Co., Inc.)
12 B-15 Richard Rao
(Reaearch-Cottrell, Inc.)
L3 D-21 H. John Heinz III, U.S.S.
(D. S. Senate)
2-2
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TABLE 2-1 (Continued)
Docket No. Comment ers...
D-22 Roger D. Freriks
(U. S, Resident)•
•15 D-27 Charles L. Sibley
(U. S. Resident)
16 D-28- Frederick Benedikt
(U. S. Resident)
17 D-29 William T. Ossmer
(Clay Citizens Coalition)
18 D-30 Glenn W. Ditsworth
(U. S. Resident)
19 ' D-31 • Earl R. Benson
(U. S. Resident)
20 D-32 ' John M. Wade
(U. S. Resident)
21 D-33 D. Lane Berrier, Jerry W. Via
(V.P.I, and S.U., Department
of Biology)
22 D-34 Mr. and Mrs. G. J. Jenkins
Mary Fielder
L. G. Fullerd
B. Prasswell
Patty Kug
Jill Kay
Bobby Frith
Edna Crapps
Mary Bolgla
Kenny Stanley
(U. S. Residents)
23 D-38 Robert L. Sandvig
(U. S. Resident)
24 D-39 Bob Packwood
(U. S. Senate)
25 D-40 Robert N. Cleveland
(Buckeye Power Inc.)
2-3
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TABLE 2-1 (Continued)
No.
26
27a
27b
28
29
30
31
32
33
34
35
36a
36b
37
Docket No.
D-41
D-42
D-43
D-44
D-45
D-46
B-48
B-49
D-50
D-52
D-53
D-55
D-57
D-58
Commenters
S. A. Shorter
(U.S. Resident)
Phillip G. Sikes
(U.S. Resident)
Dick Clark
(U.S. Senate)
and
John M. Hardie
(Iowa Public Service Company)
Helen R, Hartley
(U. S. Resident)
Evelyn E. Wardle
(0. S. Resident)
Don Schrader
(U. S. Resident)
Charles David Parent
(U. S. Resident)
Kenneth Snolinsky
(U. S. "Resident)
Gary N. Weinreieh
(American Natural Service
Co.)
Thomas A. Parkhill
(U. S. Resident)
Ron Tober
(U. S. Resident)
Mrs. Jean Kronman
(U.S. Resident)
Patrick Ragosta
(U.S. Resident)
Edward L, Sears
(U.S. Resident)
2-4
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TABLE 2-1 (Continued)
No. Docket No. Conanenters • . '
38 D-59 Robert West
(University of Virginia,
Department of Chemistry)
39 D-60 Barbara Hudgins
(U.S. Resident)
40 D-61 Marvin Bing
(U.S. Resident)
41 D-62 Phillip G. Sikes
(U.S. Resident)
42 D-63 • Andrea Wightman
Mike Moles
(U.S. Residents)
43a D-64 Ken Norstrom
(U.S. Resident)
43b D-65 Ruth C. Clusen
(Department of Energy)
44 D-67 Paul R. Hanson
(Douglas County Development
Association, Inc.)
45 D-68 Connie Okman
(U. S. Resident)
46 D-69 Catherine Alexander
(U. S. Resident)
47 B-70 Lois Binkley
(U. S. Resident)
48 D-71 Laurie Wolfe
(U. S. Resident)
49 D-72 Prank Griffith
(Iowa Public Service Co.)
50 D-73 Theodore S. May
(U.S. Resident)
51 B-74 Clarence Petty
(U.S. Resident)
2-5
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TABLE 2-1 (Continued)
Docket No. Commenters
52
53
54
55
56
57
58
59
60
61
62
63
64
D-75
D-76
D-77
D-78
D-79
Q-80
D-82
•D-83
•D-84
D-85
D-86
D-87
D-88
Alvin Blyer
(U.S. Resident
John L. Jordan
(U.S. Resident)
George Popper
(U.S. Resident)
C. David Gorton
(U.S. Resident)
Jean Hough
(U. S. Resident)
Ernest P. Kline
(Lt. Governor of Pennsylvania)
Greg H. Thompson
(U. S. Resident)
lorn Paul
(U. S. Resident)
Maria Dawn Music
(U. S. Resident)
Ken Long
(U. S. Resident)
Thane Puissegar
(U. S, Resident)
John J. LaTalee
(0. S. House of Representatives)
John J. LaFalce
John Buchanan
Tom Bevlll
Robert E. Bodham
Gulnn McKay
Walter Flowers
G. V. (Sonny) Montgomery
Henry J. Nowak
Stanley 13. Lundine
"("U, S. House of Representatives)
2-6
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TABLE 2-1 (Continued)
Mo. Docket. No. Commenters
65 D-90 Francis E. Drake, Jr.
(Rochester Gas and Electric
Corp.)
66 D-91 . Russell Toal
(U. S. Resident)
•67 D-92 Theodore F, Gies
(U. S. Resident)
68 D-93 James F. Todd, Jr.
(U. S. Resident)
69 D-94 Eleanore C. Robbins
(U. S. Resident)
70 D-95 R. Lyman Wood
(U. S. Resident)
71 D-96 . Rural Route 1
(Gentryville, Indiana)
72 D-97 Frank E. Doherty
(U. S. 'Resident)
73 D-9S - • Ron Guenther
(U. S. Resident)
74 D-99. Harold I. McNally
(U. S. Resident)
75 D-100 Dorothy R. Munn
(U. S. Resident)
76 D-101 Kirk Capper
(D. S. Resident)
77 D-102 T, A. Hendrickson
(U. S. Resident)
78 D-103 David Donnenfield
(U. S. Resident)
79 D-104 Charles F. Walter, M.D.
(U. S, Resident)
80 D-105 William E. Doughty, M.D.
(U. S. Resident)
2-7
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No.
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
TABLE 2-1
Docket No.
D-106
D-107
D-108
D-109
D-110
D-lll
D-112
D-113
D-114
D-115
D-1L6
D-117
D-118
D-119
D-120
D-121
(Continued)
Commen ters
Mary B. Daniels
(Tri-County Ranchers Assn.)
Chuck Botsko
(U.S. Resident)
Alan Nessman
(U. S. Resident)
Katy Rimball
(U. S. Resident)
Nancy L. McBride
(U. S. Resident)
Dr. Jill C. Mannisto
(U. S. Resident)
Rossella Johanson
(U. S, Resident)
I. W. Tucker
(National
Environmental Balance, Inc.)
Robert Mendelsohn
(University of Washington,
Department of Economics)
Emmett J. Ferretti, P.E.
(U. S. Resident)
Warren Little
(U. S. Resident)
Gordon "Dass" Adams
(U. S. Resident)
Robert Oset
(U. S. Resident)
Donald Tobkin
(U. S. Resident)
Brandt Mannchen
(U. S, Resident)
Rev. Daniel Crosby
(St. Labre Indian School)
2-8
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No.
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
112
TABLE 2-1 (Continued)
Docket No. Comment ers
D-122 Mark M. McClellan
(Citizens Advisory Council, Pa.)
D-123 C. Michael Reimringer
(U. S. Resident)
D-124 Wells Eddlerman
(U. S. Resident)
D--125 Rachel Matteson
(U. S. Resident)
D-126 • Sherry Cuimnings
(U. S. Resident)
D-127 Julia Corliss
(U, S. Resident)
D-128 ' Ulysses'A. Garlini
(KNOP-TV)
D-129 . • Ann A. Welch
(U. S, Resident)
D-130 Brandt Kannchen
(Slerra club)
D-131 Elanne Nusich
(U. S. Resident)
D-132 ^ A. Franklin Brayman, III, P.E.
(U. S. Resident)
Jill Ann Baxter
(U. S, Resident)
D-134 Maurice Pedriani
(Northwest Ministry of'
Lehigh Presby.tery)
D-135 ' Toby Berg
(U, S. Resident)
D-136 Brian J, Davey
(U. S. Resident)
D-137 Ernest G. Panciera
(U. S. Resident)
2-9
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o.
113
115
116
117
118
115
120
121
122
123
124
125
126
127
TABLE 2-1
Docket No.
D-138
D-139
D-140
D-141
D-142
D-143
D-144
D-145
D-146
D-147
D-148
D-149
D-150
D-151
D-152
(Continued)
Commenters
Ruth Sjarelmeyer, M.D.
(U, S. Resident)
Mr. and Mrs. Al Razor
(U. S. Resident)
Dr. and Mrs. Theodore J. Yoneida
(U, S. Resident)
Hazel H, Thompson
(U. S. Resident)
Robert H. Lyon
(U. S. Resident)
Betsy Kalbert
(U. S. Resident)
Marlene Raynor
(U. S. Resident)
D. E. Heyburn
(Babcoek & Wilcox)
"Donald Fonnan
(U. S. Resident)
J. D. Hicks
(Tampa Electric Co.)
W. M. Anderson
(U. S. Resident)
Dorothy Eoyrs
(U. S. Resident)
R. L. Hufman
(Golden Valley Electric
Assoc,, Inc.)
George Gryc
(U. S. Resident)
Harvey Bieber
(McCone Agricultural
Protection Organization)
2-10
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TABLE 2-1 (Continued)
Docket No, Comnenters
128 D-153 Robert A. Bibb, P.E.
(Lutz, Daily & Brain)
129 D-154 Michael W. Miller, M.D.
(U, S. Resident)
130 D-155 W. Bing
(U. S. Resident)
131 D-156 A. Arenal
(Southern California Edison
Company)
132 D-157 Hester McNulty
(League of Women Voters)
133 D-158 Wilbur White
Mary White
Mac White
(U. S. Residents)
134 D-159 Peter C. Lewis
(Hawaiian Electric Co., Inc.)
135 D-160 Robert C. Batson
(U. S. Resident)
136 D-161 Madeline S. Yale
(U. S. Resident)
137 D-162 Thomas J. Hogarty, M.D.
(U. S. Resident)
138 D-163 . Bruno C. Boik
(AMAX Engineering and
Management Services Co.)
139 D-164 Charlotte Hers,..
(U. S. Resident)
140 D-165 Julia Mann
(U. S. Resident)
141 D-166 - Gerald A. Jayne
(U. S. Resident)
2-11
-------
TABLE 2-1 (Continued)
Docket
Commenters
142
143
144
145
146
147
148
149
150
151
152
153
154
155a
155b
156
D-167
D-168
D-169
D-170
D-171
D-172
0-173
D-174
D-175
D-176
D-177
D-178
D-179
D-180
D-181
D-182
John M. Bardie
(Iowa Public Service Company)
S. B. Hager
(Duke Power Company)
Jane Sharp
(Conservation Council of N.C.)
George Smith
(U. S. Resident)
Danny Buck
(U. S. Resident)
Mary Ireland
(U. S. Resident)
John G. White, Jr.
(U. S. Resident)
David P. Cook
(American Lung Association)
Robert R. Wahler
(WAHLCO)
Robert K. Turner
(U. S. Resident)
Dr. Anne Harbough
(U. S. Resident)
Christopher Tesar
(Coalition for Canyon Preservation)
Herbert Deich
(MDH Industries, Inc.)
Anne H, Garde
(U. S. Resident)
George Smith
(Duplicate of D-170)
Kim DePrenger
(U. S, Resident)
2-12
-------
No.
157
158
159
160
161
162
163
TABLE 2-1 (Continued)
Docket No. -• Commenters
D-183
D-184
D-185
D-186
D-187
D-188
D-189
Glenn Walter
(U. S. Resident)
David H, Hickcox
(II. S. Resident)
Eleanor L, Buchanan
(U. S. Resident)
Mrs. Ken Christian
(U. S. Resident)
Thomas Geary
(U. S. Resident)
Marian Gerrish
(U. S. Resident)
Deleted
164
165
166
167
168
169
170
171
B-19Q
D-191
D-192
D-193
D-194
D-195
D-196
D-197
Karen Zaekheim
(D. S. Resident)
Alexander McAfee
(Cleveland-Cliffs Iron Co.)
Cynthia Jerriel
(U. S. Resident)
Marvin Cole, M.D.
(U, S. Resident)
Esther K. Epling
(U. S. Resident)
Barbara Eliversey
(U. S. Resident)
John fir Hope Kruse
(U, S. Residents)
C, Ballsun
(¥. S. Resident)
2-13'
-------
_No._
172
173
174
175
176
177
178
179
180
181
182
183
184
185
TABLE 2-1
Docket__No._
D-198
D-199
D-200
D-201
D-202
D-203
D-204
D-205
D-206
D-207
D-208
D-209
D-210
D-211
(Continued)
Commenters
Elizabeth P. Elllston
(Sandoval Environmental
Action Community)
Daniel Shubert, M.D.
(U. S. Resident)
Margaret Lopaen
(U. S. Resident)
Carol Harlow
(U. S. Resident)
Edward J. Healy
(U. S. Resident)
Herman A. Fritschen
(Cities Service Company)
K. M. Wilson, P.E.
(Coal Tech)
Robert V. Tanner
(Santee Cooper, South Carolina
Public Service Authority)
Gerald McGowan
(Lear Siegler, Inc.)
Richard F. Straub
(U. S. Resident)
Clifford Bove
(U. S. Resident)
Mr. and Mrs. Stuart A. More
(U. S, Residents)
J, R. Endicott
(Board of Public Utilities, City
of Coldwater, Mont.)
John R. Bartlit
(New Mexico Citizens for Clean
Air & Water, Inc.
2-14
-------
TABLE 2-1 (Continued)
Mo. Docket No. Commente_rs
186 D-212 Alfred T. Whatley, Ph.D.
(Air Pollution Control Commission,
Colorado Department of Health)
187 • D-213 Hugh Zackheim
(Montana Wildlife Federation)
188 D-214 Sandra Gajkowski
(American Steamship Company)
189 D-215 W. G, Crosby
(South Carolina Department of
Health and Environmental Control)
190 D-216 C. M. Heidel
(Detroit Edison)
191 D-217 Bruce Beyrest
(Chevron U.S.A., Inc.)
192 D-218 John M. Daniel, Jr,» P.E.
(Commonwealth of Virginia, State
Air Pollution Control Board)
193 D-219 Carlton Rush
(The Cleveland Electric
Illuminating Company)
194 D-220 Stephen J. Knapp
(U. S. Resident)
195 D-221 Mr. and Mrs. Art Hayes, Jr.
(U. S. Residents)
196 D-222 Nora Hope
(U. S. Resident)
197 D-223 . F. W, Lewis
(Middle South Services, Inc.)
198 D-224' N. R. Lee
(Gulf States Utilities Company)
199 D-225 Harry L. Blomquist, Jr.
(Coastal States Gas Corporation)
2-15
-------
No.
200
201
202
203
204
205
206
207
208
209
210
211
212
213
TABLE 2-I (Continued)
Docket No.
D-226
D-227
D-228
D-229
D-23Q
D-231
D-232
D-233
D-234
D-235
D-236
D-237
D-238
D-239
Gonmenters
Katherine Spers
(U. S, Resident)
James B, Edwards, Governor
(State of South Carolina)
Michael Wustine
(U. S. Resident)
Betty Woodruff
(League of Woman Voters of
Missouri)
Dr. Michael D. Williams
(New Mexico Citizens for Clean
Air and Water)
John L. Wood
(Control and South West Services)
Frank Linder
(Dairyland Power Cooperative)
W. H. Krone George
(Aluminum Company of America)
S. J. Sweeney
(Boston Edison Company)
Tom Kenny
(D. S. Resident)
Robert Potter
(U. S. Resident)
Samuel J. Tuthill
(Iowa Electric Light and Power
Company)
James F. Coerver
(Louisianna Air Control Commission)
Craig M. Weaver
(U. S. Resident)
2-16
-------
214
215
216
217
218
219
220
221
222
223
224
225
226
227
TABLE 2-1
Docket No.
D-240
D-241
D-242
D-243
D-244
D-245
D-246
D-247
D-248
D-249
D-250
D-251
D-252
D-253
(Continued)
Commentgrs_
C, M. Woodstock
(U. S. Resident)
Richard Hopkins
(U. S. Resident)
P. F. Gorman
(Chas, T, Main, Inc.)
Frank C. Perunko
(U. S, Resident)
David D. Drake
(Dept. of Energy, Frankfort,
Kentucky)
Frank Clements
(United Mine Workers of America)
Keven Greene
(Citizens for a Better
Environment)
Sidney R. Oretn
(Industrial Gas Gleaning
Institute, Inc.)
Richard A. Weber, D.D.S.
(U. S. Resident)
Russel V, Handle
(Yale Law School)
M. L, Hurstell
(Mew Orleans Public Service Co.)
W. W. Kroeber
(Montana-Dakota Utilities Co.)
Virgil E. Peterson
(Hassier Energy)
E. E. Hall
(Pacific Gas and Electric
Company)
2-17
-------
No.
228
229
230
231
232
233
234
235
236
237
238
239
240
241
TABLE 2-1 (Continued)
Docket No. Conmenters
D-254
D-255
D-256
D-257
D-258
D-259
D-260
D-261
D-262
D-263
D-264
D-265
D-266
D-267
W. T. Slick, Jr.
(Exxon Company, U.S.A.)
S. B. Milligan
(The Rust Engineering Company)
R. C, Kuether
(Kansas Power and Light Company)
Joseph A. Schuls
(The Pittston Company Coal Group)
Dennis R. Nelson
(U. S. Resident)
Gene H. Gockley
(Pennsylvania Power & Light Co.)
Don Gasper
(ff, Va. Dept. of Natural Resources)
John A. Scarola
(EBASCO Services Incorporated)
H. E. Bond
(Atlantic Richfield Company)
J. D. Phillips
(City of Colorado Springs)
Ed Malenovsky
(0. S. Resident)
Steve Berg-Hansen
(Rocky Mountain Energy Company)
Claude M. Scales, III
(Orange and Rockland Utilities,
Inc.)
John J. Dyson
(Department of Commerce,
State of New York)
2-18
-------
TABLE 2-1 (Continued)
Docket No. Conmenters
242
243
244
245
246
247
D-268
D-269
D-27G
D-271
D-272
D-273
Thomas C. Austin
(Air Resources Board, State of
California)
Noel and Irene Rosetta
(U. S. Residents)
Christopher S. Bond
Charles A. Blackmar
(U. S. Residents)
Edward G. Weber
(Southwestern Public Service)
R. E. Parnelle
(Florida Power Corporation)
Walter G. Saunders, M.D., F.A.C.O.G.
(U. S. Resident)
248
249
250
251
252
253
D-274
D-275
D-276
D-277
D-278
D-279
T. V. Lennick
(Cooperative Power Association)
R. Bruce Campbell
(U. S. Resident)
James Fish
(Great Lakes Commission)
W. H, Axtman
(American Boiler Manufacturer
Association)
Andy P, Bartson
(U. S. Resident)
John R. Hopkins
(U. S. Resident)
2-19
-------
No.
254
255
256
257
258,
259
260
261
262
263
264
265
266
267
268
TABLE 2-1 (Continued)
Docket No. Commettters
D-280 Gary L. Allison
(Wheelabrator Cleanfuel Corporation)
D-281 ' Mr. and Mrs. J. Lewis
(U.S. Resident)
D-282 Cal Wilson
(U.S. Resident)
D-283 F. W. Giaaccone
(EPA, Air Facilities Branch)
D-284 Ted Schwinder, Acting Governor
(State of Montana)
D-285 Ann C. Rick
(League of Women Voters of West
Va,, Inc.)
D-286 John M. Daniel, Jr., P.E.
(State Air Pollution Control
Board, Virginia)
D-287 A. E. Pearson
(Nevada Power Company)
D-288 Pred A. Shiosakl
(The Washington Power Company)
D-289 Lloyd McCaskey
(Oakdale Electric Cooperative)
D-290 Robert C. Weaver
(National Association of Counties)
D-291 Henry Peck
(U.S. Resident)
D-292 Steve Rice
(U.S. Resident)
D-293 James H. Hughes
(U.S. Resident)
D-294 Richard Adler
(Clark Electric Cooperative)
2-20
-------
No.
269
270
271
272
273
274
275
276
277
278
279
280
281
282
TABLE 2-1 (Continued)
Docket No.
D-295
D-296
D-297
D-298
D-299
D-300
D-301
D-302
D-303
D-304
D-305
D-306
D-307
D-308
Commenters
Helen R. Hartley
(U.S. Resident)
Steven Doelder
(U.S. Resident)
Victor N. Peterson
(Pierce-Pepin Electric Cooperative)
Mr. Philip Parker
(Polk-Barnett Electric Cooperative)
Virgil M. Dufeck
(Eau. Claire Electric Cooperative)
Virgil C. Summer
(South Carolina Electric and
Gas Company)
W. H, Axtman
(American Boiler Manufacturers
Association)
Spencer P. Felt
(The National Filter Media
Corporation)
Thomas A. Parkhlll
(U.S. Resident)
J. D. Selby
(Consumers Power Company)
William L. Perdue
(The Kansas Power and Light Company)
Jerrold L. Jacobs
(Atlantic Electric)
William F. Sytaons
(Atlantic Electric)
W. G. Kuhns
(General Public Utilities Corp.)
2-21
-------
No.
283
284a
284b
284c
285
286
287
288
289
290
291
292
293
TABLE 2-1 (Continued)
Docket No. Commenters
D-309 V. J. Daniel, Jr.
(Mississippi Power Company)
and
Trent Lott
(U.S. House of Representatives)
D-310 V. J. Daniel, Jr.
(Mississippi Power Company)
and
GilLespie V, Montgomery
(U.S. House of Representatives)
D-311 Stuart E. Eizenstaat
(Assistant to the President, The
White House)
D-312 Stuart E. Sizenstaat
(Assistant to the President, The
White House)
D-313 J. A. Stuart
(South Coast Air Quality Mgrnnt. District)
D-314 L. E. Zeni
' (Department of Natural Resources,
State of Maryland)
D-315 A. E. Kintigh
(New York State Electric and
Gas Corporation)
D-316 •Richard Dorgan
(U.S. Resident)
D-317 John M. Arthur
(Duquesne Light Company)
D-318 E. J. Evans
(U. S. Resident)
D-319 Earl L. Johnson
(Tri-County Electric Cooperative)
D-320 Roger A. Hofacker
(Western Systems Coordinating
Council)
D-321 Wayne R. Johnson
" (Kansas City Power and Light Company).
2-22
-------
TABLE 2-1 (Continued)
Mo. Docket No. . Commenters
294 D-322 F. K. Smith
(Texas Municipal Power Agency)
295 D-323 • • Carolyn Embry
(U.S. Resident)
296 ' D-324 Jim Jontz
(House of Representatives
State of Indiana)
297 D-325 Robert H. Short
(Portland General Electric Co.)
298 D-326 Robert J. Reichelderfer
(First Presbyterian Church)
299 D-327 ' James Conroy
(U.S. Resident)
300 D-328 Keith Guelff
(U.S. Resident)
301 D-329 " Jacob T. Lee
(Dunn County Electric Cooperative)
302 . D-330 D. L. Renberger
(Washington Public Power Supply System)
303 D-331 ' '' Lois J. Imhoff
(The League of Women Voters of Arkansas)
304 D-332 John J, LaFalce
(U.S. House of Representatives)
305 ' " D-333 Herman E. Talmadge
(U.S. Senate)
306 '• ' • D-334 Ray Roberts.
Sam B. Hall
'Omar Buries on
' . ' Ahrahani Kazan
William Mattox
W. R. Poage
• Charles Wilson
Tale Malford
J. Hightower
Ali E. Teague
Henry B. Gonzales
J. J. Pickle
Bob Krueger
George Mahon
(U.S. House of Representatives)
2-23
-------
No.
307
308
309
310
311
312
313
314
315
316
317
318
319
TABLE 2-1 (Continued)
Docket No. Commenters
D-335 Frank W. Griffith
(Iowa Public Service Company)
D-336 W. Henson Moore
(U.S. House of Representatives)
D-337 Janice L. Whitten, M.C.
(U.S. House of Representatives)
D-338 Dan Daniel
(U.S. House of Representatives)
I>-339 Norman E. D'Amours
(D.S. House of Representatives)
and
Russell A. Holden
(New England Power Company)
D-340 Charles H. Percy
(U.S. Senate)
and
Kenneth L. Andres
(Central Illinois Public Service Co.)
D-341 Allyn M. Davis
(U.S. EPA, Air and Hazardous Materials
Division)
D-342 Mrs. Magdelene S. Atkinson
(U.S. Resident)
D-343 M. G. Kuhns
(General Public Utilities Corp.)
and
William A. Verrochi
(Pennsylvania Electric Company)
D-344 Charles E. Grassley
(U.S. House of Representatives)
D-345 Francis E. Drake, Jr.
(Rochester Gas and Electric Corp.)
D-346 Norman A. Johnson, Jr.
(Mississippi Public Service Commission)
D-347 A. Frank Brayman III, P.E.
(U.S. Resident)
2-24
-------
TABLE 2-1 (Continued)
No. Docket No. Commenters
320 D-348 M. Caldwell Butler
i (U.S. House .of Representatives)
321 D-349 R. L. Hufman
, (Golden Valley Electric Assn.,. Inc.)
322 D-350 Hubert B. Erwin
(California Lung Association.)
323 .D-351 Loren L. Roberts
(Long Beach Lung Association)
324 •• • -. . D-352 , • Harry W. Read
. > ' •• • Beverly A. Bermacher.
(U.S. Residents)
325 • • .' ' D-353 ' Marlene and Gaylord Yost
(U.S. Resident)
326 • -' D-354 •• • . Larry Schultz
(The Izaak Walton League of
America, Inc.)
327 D-355 Bernard P. Wolff, M.D.
" '" (Georgia Lung Association)
328 D-356 Eichard Hopkins
- -- ' (U.S. Resident)
329 D-357 Cecile Helsel
(City of Superior, Wisconsin)
330 D-358 Lewis C. Green
(Green, Henning & Henry)
331 D-359 Howard E. Hesketh, P.E.
"(U.S. Resident) . -
332 D-360 Ben Chaiken
--•(Arizona Lung Association)
333 D-361 Earl L. King
(Allied Power Cooperative of Iowa)
334 D-362 Mrs. Jean Ingold
(U.S. Resident)
335 D-363 Walter Dickinson, Jr.
(American Lung Association)
2-25
-------
No.
TABLE 2-1 (Continued)
Docket No.
Commentsrs
336
337
338
339
340
341
D-364
D-365
D-366
D-367
D-368
B-369
342
343
344
345
346
347
348
349
350
B-370
D-371
D-372
D-373
D-374
D-375
D-376
D-377
D-378
Walter L. Zadan
(Group Against Smog and Pollution)
Mr. Burnet D. Brown
(U.S. Resident)
Ernst W. Mueller
(Dept. of Environmental Conservation,
State of Alaska)
Robert A. Arnatt, Ph.D
(Dept. of Natural Resources,
State of Wisconsin)
J. L. Lombardo
(Island Creek Coal Company)
S. D. Goodman
(Gilbert Associates, Inc.)
Karl H. Schafer
(Iowa-Illinois Gas and Electric Co.)
James C. Wilson
(Rocky Mountain Energy Company)
Hazel Odegard
(U.S. Resident)
James L. Grahl
(Basin Electric Power Corporation)
Tom Quiiffl
(Governor's Office, State of Calif.)
Ron Crouch
(Sierra Club, Cumberland Chapter)
Rev. Carleton Schaller, Jr.
(U.S. Resident)
Bernard Perry
(U.S. Resident)
Anthony L. Van Geet, Ph.D.
(U.S. Resident)
2-26
-------
TABLE 2-1 (Continued)
No. Docket Ho. Commenters
351 D-379 Kathleen Hultgren
(U.S. Resident)
352 D-380 W. Donham Crawford
(Gulf States Utilities Company)
353 . D-381 Marshall C. Deason, Jr.
(American Lung Association of
Southeast Florida, Inc.)
354 - - D-382 V. J. Holmes
(U.S. Resident)
355 • , D-383 - Glenn Morazzine
(U.S. Resident)
356 D-384 Glen A. Ramsdell, M.D.
(American Lung Assn. of Indiana)
357 D-385 Ruth M. Young
(U.S. Resident)
358 D-386 Irving Mushlin
(Dade-Monroe Lung Association, Inc.)
359 D-387 Powell Foster
(U.S. Resident)
360 D-388 Charles- Schultze
Barry Boswcrth
(Lung Association of San Diego
and Imperial Counties)
361 -D-389- James T. Allison
(Mid-Memphis Improvement Assn.)
362 D-390 Elaine Walker, R.R.T.
(American Lung Association)
363 D-391 Priscilla G. Robinson
(Southwest Environmental Service)
364 D-392 Fay Witz
(City of Highland Park, Illinois)
365 D-393 Norman 0. Stein, Ph.D.
(American Lung Association)
2-27
-------
TABLE 2-1 (Continued)
No. Docket No. Commenters
356 D-394 Beryl Reichenberg
(Clean Air Coalition)
3S7 D-395 John and Marilyn Layon
(U.S. Resident)
368 D-396 John C. Bhend
(U.S. Resident)
369 D-397 D< T- Berube
(The Montana Power Company)
370 D-398 Donald Samsen
(St. Croix County Electric
Cooperative)
371 D-399 Don E- Gerard
(Board of Public Utilities,
McPherson, Kansas)
372 D-400 Lawrence L. Eoeser
(Arizonans for Jobs and Energy)
373 D-4Q1 Jota J. Bergan
(Colorado-Ute Electric Assn., Inc.)
374 - D-402 William F. Matson
(Allegheny Electric Cooperative, Inc.)
375 D-403 Gerald G. Bachman
(Mid-Continent Area Power Pool)
376 D-404 D. D. Jordon
(Houston Lighting and Power Company)
377 D-405 William W. Llyons
(Northern Energy Resources Company)-
378 D-406 James A. Patton
(Northern Plains Resource Council)
379 D-407 Eric N. Sloth, Ph.D.
(Nebraska Public Power District)
380 D-408 Irvin D. Parker
(Dept. of Consumer Affairs, State
of South Carolina)
2-23
-------
381
382
383
384
385
386
387
388
389
390
391
392
393
394
395
396
TABLE 2-1 (Continued)
Docket No. Coirnnenters
D-409 J. R. Thorpe
(GPU Service Corporation)
. D-410 John W. Ellis
(Puget Sound Power and Light Co.)
D-411 Priscilla Maclean
(League of Women Voters of Montana)
D-412 ' G. P. Reidy
(The CAM Company)
D-413 S. David Freeman
(Tennessee Valley Authority)
D-414 Donald C, Lutken
(Mississippi Power and Light Company)
D-415 W. M. Taylor
(Texas Electric Service Company)
D-416 Alan Beals
(National League of Cities)
D-417 • D. R. Betterton
(Houston Lighting and Power)
D-418 Dr. T.A. Vanderslice
(General Electric Company)
D-419 Economic Development Council
of Northeastern Pennsylvania
D-420 H. John Heinz III, U.S.S.
(United States Senate)
D-421 Glenn G.C. Olson
(Northern States Power Company)
D-422 Clarence R. Feldman
(Americans for Energy Independence)
D-423 Jay D. Myster
(Otter Tail Power Company)
D-424 Abe H. Frumkln
(representing the Anthracite Develop-
ment and Utilization Association)
2-29
-------
Ho,
397
398
399
400
401
402
403
404
405
406
407
408
409
410
411
TABLE 2-1 (Continued)
Docket No. Commentera
D-425 John R. McNamara
(WEST Associates)
D-426 Arthur D. Rheingold
(American Electric Power Service Co.)
D-427 Kent Briggs
(behalf of Scott M. Matheson,
Governor of Utah)
B-428 Mr. and Mrs. Gordon Waller
(U.S. Residents)
D-429 ' S.B. Jacobs
(Stone and Webster
Engineering Corporation)
D-430 Leroy Michael, Jr.
(Salt liver Project)
D-431 John A. Scarola
(Ebasco Services Incorporated)
D-432 Patty Kluver
(U.S. Resident)
D-433 Gerald G. Bachman
(Nebraska Power Industry
Committee)
B-434 Wallace D. McRae
(Rosebud Protective Association)
D-435 ' A.E. Michon
(Burlington Northern)
D-436 Arthur F. Armstrong
(Contraves Goerz Corporation)
D-437 G. E. Watson
(Dallas Power and Light" Company)
D-438 James H. Anthony
(Intermountain Power Project)
D-439 Delaware Valley Citizen's Council
for Clean Air
2-30
-------
TABLE 2-1 (Continued)
No- Docket No. Commenters
412 D-440 A. L. Cahn
(Bechtel Power Corporation)
413 D-441 Jerilyn E. Bieher
(MeGone Women Involved in Farm
Economics)
414 D-442 Richard J. Grant
(Central Illinois Public Service Co.)
415 D-443 L. A. McReynolds
(Phillips Petroleum Company)
416 D-444 James K. Hambright
(Bureau of Air Quality Control,
Pennsylvania)
417 D-445 Keith Molin
(Dept. of Commerce, Michigan)
418 D-446 Curtis L. Ritland
(Iowa Power)
419' ' D-447 A.O. Courtney
(Commonwealth Edison)
420 D-448 James L. Mulloy
(Department of Water and
Power, City of Los Angeles)
421 D-449 Joseph E. Fulton
(City Public Service Board of
San Antonio, Texas)
422 D-450 H.E. Bond
(Atlantic Richfield Company)
423 D-451 James F. Purcell
(Northern Indiana Public Service Co.)
424 - D-452 James N. Howell
(Great Lakes Steel Div. of National
Steel Corporation)
425 D-453 Russell V. Handle
(Yale Environmental Law School)
426 D-454 Matthew Gould
(National Assn. of Manufacturers)
2-31
-------
TABLE 2-1 (Continued)
No. DocketNo. Commenters
427 D-455 Richard D. McRanie
(Southern Company Services)
428 D-456 Dean B, Suagee
(U.S. Resident)
429 D-457 James1 Barrett
(Michigan State Chamber of
Commerce)
430 D-458 Peter H. Benziger
(Potomac Electric Power
Company)
431 D-459 Mary Ellen Schraeder
(Department of Public Property,
Springfield, Illinois)
432 D-460 Walter T. Woelfle
(Wisconsin Electric Power
Company)
433 D-461 Andrew T. Bahn, P.E.
(Illinois Power Company)
434 D-462 Paul H. Arbesman
(Department of Environ-
mental Protection, New Jersey)
435 D-463 . Joe L. Gremban
(Sierra Pacific Power Company)
436 D-464 Robert A. McKn-ight
(Indianapolis Power and Light
Company)
437 D-465 David M. Anderson
(Bethlehem Steel Corporation)
438 B-466 S,F, Sherwood
(El Paso Coal Company)
439 D-467 Paul C. Kittle
(Consumers Power Company)
2-32
-------
TABLE 2-1 (Continued)
441
442
443
444
445
446
Docket No.
D-468
D-469
D-470
D-471
D-472
D-473
D-474
447
448
D-475
D-476
Commentera
Victoria Potter
(State of Wisconsin)
Paul Ember, Jr.
Richard C. Clancy
(Utility Solid Waste
Activities Group)
Louis R. Paley
(U.S. EPA)
Morris L. Brehmer, Ph.D.
(Vepco)
Jarrell E. Southall
(Department of Pollution
Control and Ecology,
State of Arkansas)
William L. Keepers
(Wisconsin Power and
Light Company)
Edward Berlin and
Andrew D. Weissman representing
Appalachian Power Company,
Boston Edison Company,
Commonwealth Edison Company,
Consolidated Edison Company
of New York, Inc., Florida
Power and Light Company,
Indiana and Michigan Electric
Company, Kentucky Power Company,
Kingaport Power Company,
Michigan Power Company, Ohio
Power Company, Union Electric
Company, Wheeling Electric
Company
D.L. Aswell
(Louisiana Power and Light)
Charles L. Tyree
(Oklahoma Gas and Electric
Company)
2-33
-------
No.
449
450
451
452
453
454
455
TABLE 2-1 (Continued)
Docket No.
Commenters
456
457
458
459
460
D-477
D-478
D-479
D-480
D-481
D-482
D-483
D-484
D-485
D-486
D-487
D-488
W. Samuel Tucker, Jr.
(Florida Power and Light Co.)
James H. Evans
(The Business Roundtable)
Bert Roark
(Dept. for Natural Resources
and Environmental Protection,
State of Kentucky)
A.H. Massah
(Mobil Oil Corporation)
Verl R. Topham
(Utah Power and Light Co.)
Charles A. Zielinski
(Public Service Commission,
State of New York)
Scott M. Turner
(Nixon, Margrave, Devans
& Doyle, representing
Rochester Gas and Electric
Company)
Douglas L« McCrary
(Southern Company Services, Inc.)
J,L« Morgan
(The American Society of
Mechanical Engineers)
E.R. Kilpatrick
(Minnesota Power and Light
Company)
Ernest P. Kline
(Lieutenant Governor,
State of Pennsylvania)
John D. Janak
(Texas Utilities
Services, Inc.)
2-34
-------
TABLE 2-1 (Continued)
No. Docket No. Commenters
461 D-489 David S. Potter
(General Motors Corporation)
462 D-490 American Public Power
Corporation
463 D-491 George C. Freeman, Jr.
(Hunton and Williams,
representing the Utility Air
Regulatory Group)
464 - D-492 Richard T. Myren
(U.S. Resident)
465 D-493 William E. Culbreath, Jr.
(Florida Lung Association)
466 D-494 Faith Hunt Tjardes
(American Lung Association
of Colorado)
467 D-495 Lauretta Rice
(League of Women Voters of
San Luis Obispo, California)
468 D-496 Patrick Brouty
(U.S. Resident)
469 D-497 G. Richard Day
(Kentucky Lung Association)
470 D-498 William C. Jacquin
(Arizona Chamber of Commerce)
471 D-499 James W. Morrow
(American Lung Association
of Hawaii)
472 D-500 Mildred Engelberg
(U.S. Resident)
473 D-501 Alexander Sagady
(Michigan Lung Association.)
474 D-S02 Clive Mutschler
(U.S. Resident)
2-35
-------
No._
475
476
477
478
479
480
481
482
483
484
485
486
487
488
489
TABLE 2-1 (Continued)
Docket No,
Commenters
D-503
D-504
D-505
D-5G6
D-507
D-508
D-509
D-510
D-511
D-512
D-513
D-514
D-515
D-516
D-517
Billie Dytzel
(New Mexico Lung Association)
Lori Franklin
(U.S. Resident)
Paul H. Arbesman
(Dept. of Environmental
Protection, New Jersey)
Emma Hartzler
(U.S. Resident)
Brad Bortner
(University of Vermont)
David B. Tegart
(Western Environmental Trade
Association, Inc.)
Evelyn Volpe
(U.S. Resident)
Carl Pope
(Sierra Club)
Arnold Miller
(United Mine Workers of
America)
Harold F. Elkin
(Sun Company)
Richard C. Dolsemer
(U.S. Resident)
James C. Wilson
(Western Regional Council)
Donald B. Ricky
(Mid-Valley Lung Association)
James L. Bechtold
(Northern States Power Company)
Ethel Morten
(U.S. Resident)
2-36
-------
TABLE 2-1 (Continued)
No. Docket Ho. Commenters
490 D-518 Diane Brown
(League of Women Voters of Oklahoma)
491 D-519 Douglas L. McCrary
(Southern Company Services, Inc.)
492 D-520 R. L. Hufman
(Golden Valley Electric Assn., Inc.)
493 D-521 Ahti A. Erkkinen
(U.S. Resident)
494 D-522 Fay Witz
(City of Highland Park,
Illinois)
495 D-523 E.R. Bingham
(AMAX Environmental
Services, Inc.)
496 D-524 John R. Bartlit
(New Mexico Citizen for
Clean Air and Water)
497 D-525 ' Clarence Petty
(U.S. Resident)
498 D-527 Henry S. Reuss
(U.S. House of Representatives)
and
James R. Underkofler
(Wisconsin Power & Light Co.)
499 D-528 Clement J. Zablocki
(U.S. House of Representatives)
and
James R. Underkofler
(Wisconsin Power & Light Co.)
500 D-529 William J. Hughes
(U.S. House of Representatives)
and
Jerrold Jacobs
(Atlantic City Electric Co.)
2-37
-------
TABLE 2-1 (Continued)
Tag.. Docket No. Commenters
501 D-530 S. I. Hayakawa
(U.S. Senate)
and
Hugh W. Evans
(U.S. Resident)
502 D-531 ' John J. LaFalce
John Buchanan
Tom Bevill
. Robert E. Badham
Gunn McKay
Walter Flowers
G.V. Montgomery
Henry J. Nowak
Stanley N. Lundtae
(U.S. House of Representatives)
503 D-534 Mlllicent Fenwick
(U.S. House of Representatives)
and
Jerrold L. Jacobs
(Atlantic City Electric)
504 D-535 Robert W. Kastemaeier
(U.S. House of Representatives)
and
James R. Underkofler
(Wisconsin Bower & Light Company)
505 D-536 Eobert A. Roe
(U.S. House of Representatives)
and
Jerrold L. Jacobs
(Atlantic City Electric)
506 D-537 G. William Whitehurst
Paul Trlble
. (U.S. House of Representatives)
and
Harry F. Byrd, Jr.
(U.S. Senate)
and
Stanley Ragone
(Virginia Electric and Power Co.)
2-38
-------
TABLE 2-1 (Continued)
No. Docket No. Commenters
507 D-538 Gillespie V. Montgomery
(U.S. House of Representatives)
and
V.J. Daniel, Jr.
(Mississippi Power Company)
508 D-539 Les Aspin
(U.S. House of Representatives)
and
Philip G. Sikes
(U.S. Resident)
509 D-540 • Lindy Boggs
(U.S. House of Representatives)
and
J.M. Mooney
(Louisiana Power and Light)
510 D-541 James 0, Eastland
(U.S. Senate)
and
V.J. Daniels, Jr.
(Mississippi Power Company)
511 D-542 John C. Stennis
(U.S. Senate)
512 D-543 J. Bennett Johnston
(U.S. Senate)
and
J.M, Mooney
(Louisiana Power and Light)
513 D-544 Gillis W. Long
(U.S. House of Representatives)
and
J.M. Mooney
(Louisiana Power and Light)
514 D-545 Thomas O'Neill, Jr.
(U.S. House of Representatives)
and
William J. Cadigan
(Massachusetts Electric)
2-39
-------
TABLE 2-1 (Continued)
No. Docket No. Conmienters
515 D-547 Eobert L. Livingston
(U.S. House of Representatives)
516 D-548 Joel Pritehard
(U.S. House of Representatives)
and
Don C. Frisbee
(Pacific Power & Light Co.)
517 D-549 Jeffrey Nedelman
(U.S. Senate)
and
Cecile Helael
(City of Superior, Wisconsin)
518 D-550 Gus Yatron
(U.S. House of Representatives)
and
Walter M. Creitz
(Metropolitan Edison Co.)
and
W.G. Kuhns
(General Public Utilities Corp.)
519 D-551 Emery Nemethy
(Ecology/Alert)
520 D-552 Malcolm Wallop "
(U.S. Senate)
521 D-553 John M. Daniel, Jr.
(Commonwealth of Virginia,
State Air Pollution Control Board)
522 D-554 Robert Hibbard
(Pennsylvania Chamber of Commerce)
523 D-555 Margaret M. Heckler
(U.S. House of Representatives)
and
William J. Cadigan
(Massachusetts Electric)
524 D-556 Thad Cochran
(U.S. House of Representatives)
2-40
-------
TABLE 2-1 (Continued)
No. Docket No. Commenters
525 D-557 Russell B. Long
(U.S. Senate)
and
J.M. Mooney
(Louisiana Power and Light)
526 D-558 Paul Findley
(U.S. House of Representatives)
527 D-559 ' George C. Freeman, Jr.
(Hunton & Williams representing
Utility Air Regulatory Group)
528 D-560 Edward M. Kennedy
(U.S. Senate)
and
William J. Cadigan
(Massachusetts Electric Co.)
529 D-561 John Melcher
(U.S. Senate)
530 D-562 Don Young
(U.S. House of Representatives)
531 D-563 Warren G. Magnuson
(U.S. Senate)
and
Don C. Frisbee
(Pacific Power & Light Co.)
532 D-5S4 Reed Zars
(Powder River Basin Resource
Council)
533 D-565 Ethel W. Thorniley
Mr. & Mrs. S. Poland
Mr. & Mrs. L. Rusan
Ms. D. Farman
Mr.' & Mrs. T. Szabo
Mr. & Mrs. R. Angst
Mr. & Mrs. G. Manz
Mr. & Mrs. C. Paddock
Mrs. N. Trost
Mr. & Mrs. A. Morency
(U.S. Residents)
2-41,
-------
TABLE 2-1 (Continued)
Ho. Docket No. Commenters
534 D-566 Marty Bender
(U.S. Resident)
535 D-567 Leilani Zutrau
(U.S. Resident)
536 D-568 Wm, J. Basiliere.
(U.S. Resident)
537 D-569 Meg Titus
(League of Women Voters of
Texas)
538 D-570 Tracy Caldewey
(U.S. Resident)
539 D-571 Frank leal
(State of Illinois, Institute
of Natural Resources)
540 D-572 J. Stewart Frame
(U.S. Resident)
541 D-573 Robert B. Ludgate
(Pennsylvania Society of
Professional Engineers)
542 D-574 Julio Hernandez-Fragoso
(Puerto Rico Water Resources
Authority)
543 D-575 A. E. Michon
(Burlington Northern)
544 D-576 Helen Jacobs
(Southeastern Wisconsin Coalition
for Clean Air, Technical Committee)
545 D-577 Robert S. Anderson
(U.S. Resident)
546 0-578 Peter S. Duncan
(Commonwealth of Pennsylvania,
Joint Legislative Air and Water
Pollution Control and Conservation
Committee)
2-42
-------
TABLE 2-1 (Continued)
No. Docket No. Commenters
547 D-579 Ed Herschler
{Governor of Wyoming)
548 D-580 John J. Bugas
(Colorado-Ute Electric
Association, Inc.)
549 D-581 Julian M. Carroll
(Governor of Kentucky)
550 B-582 John A. Scarola
(Ebasco Services)
551 D-583 James L. Grahl
(Basin Electric Power Cooperative)
552 D-584 Joseph S. Ives
(National Rural- Electric
Cooperative Association)
553 D-585 W.G. Hegeoer
(Sargent & Ltindy Engineers)
554 D-586 William F. Zunker
(CNB Tri-Fuel Boiler)
555 D-587 Abe H. Frumkin, Esq.
(representing the Anthracite
Development and Utilization
Association)
556 D-588 D.F. Barrett
(E.I. DuPont De Nemours & Company)
557 B-589 Leroy Michael, Jr.
(Salt River Project)
558 D-59Q Patricia Schroeder
(U.S. House of Representatives)
559 D-591 Gary L. Allison
(Wheelabrator Chemical Corp.)
560 D-592 Safe Pomerance
(National Clean Air Coalition)
2-43
-------
No.
561
562
563
564
565
566
567
568
569
570
TABLE 2-1 (Continued)
Docket No. Coranenters
D-593
D-594
D-595
D-596
D-597
D-598
D-599
D-600
D-601
D-602
James L. Bechthold
(Northern States Power Company)
Kay Troitino
(U.S. Resident)
G. William Whitehurst
Robert W. Daniel, Jr.
(U.S. House of Representatives)
and
Durwood S. Curling
(Southeastern Public Service
Authority of Virginia)
Mark 0. Hat field
(U.S. Senate)
and
Don C. Frisbee
(Pacific Power & Light Company)
Toin Quinn
(California Governor's Office)
Bill Proxmire
(U.S. Senate)
and
Cecile Helsel
(City of Superior, Wisconsin)
David C. Treen
(U.S. House of Representatives)
Mark 0. Hat field
(U.S. Senate)
and
Kenneth ¥. Self
(Freightliner Corporation)
Lewis C, Green
(Green, Hennings & Henry represent-
ing the Coalition for the Environment)
William B. Harral
(Commonwealth of Pennsylvania,
Governor's Office)
2-44
-------
Ho.
571
572
573
574
575
576
577
578
579
580
581
582
TABLE 2-1 (Continued)
Docket No. Commenters
D-603 Henry V. Nickel
(Hunton & Williams representing
the Utility Air Regulatory Group)
D-604 Not a comment letter
D-605 Gaylord Nelson
(U.S. Senate)
D-606 Dennis G. Seipp
(Goal Coordinator, Commonwealth
of Pennsylvania)
D-607 Vincent B, Makowski
(Solicitor, Borough of Marion
Heights, Pennsylvania)
D-608 Frank L. Blackhall
(U.S. Resident)
D-609 Gary Hubenstein
(State of California Air
Resources Board)
D-610 William E. Albers
(The Appalachian Regional
Commission)
D-611 Henry V. Nickel
(Hunton. & Williams representing
the Utility Air Regulatory Group)
D-612 Ray Thornton
(U.S. House of Representatives)
and
Arch Pettit
(Arkansas Power & Light Company)
D-613 Harold T. Johnson
(U.S. House of Representatives)
D-614 David R. Bowen
(U.S. House of Representatives)
2-45
-------
No.
583
TABLE 2-1 (Continued)
Docket No. Commenters
584
585
586
587
588
589
590
591
592
593
594
D-615
D-616
D-617
D-618
D-619
D-620
D-621
D-622
D-623
D-624
D-625
D-626
Lawton Chiles
(U.S. Senate)
and
E.L. Addisan
(Gulf Power Company)
William H. Harsha
(U.S. House of Representatives)
Mark 0. Hatfield
(U.S. Senate)
and
William W. Lyons
(Northern Energy Resources Co.)
Les AuCoin
(U.S. House of Representatives)
and
William Lyons
(Northern Energy Resources Co.)
Robert R. Wahler
(Wahlco)
W,M. Irving
(Jacksonville Electric Authority)
Peter J. Walley
(Mississippi Fuel & Energy
Management Commission.)
Daniel Shubert, M.D.
(U.S. Resident)
Merilyn Eeeves
(American Lung Association
of Maryland, Inc.)
Michael Laurie
(U.S. Resident)
H. E. Bond
(Atlantic Richfield Company)
Joseph J. Brecher
(representing The Sierra Club)
2-46
-------
No.
595
596
597
598
599
600
601
602
603
TABLE 2-1 (Continued)
Docket No. Coimienters
D-627
D-628
D-629
D-630
D-631
D-632
D-633
D-634
D-635
604
D-636
J. Louis York
(Stearns-Roger, Inc.)
Gene H. Glockley
(PP&L)
C. Frank Horscher, III
(Dept. for Natural Resources
and Environmental Protection,
Commonwealth of Kentucky)
Joseph W. Mullan
(National Coal Association)
Richard E. Ayres
(Natural Resources Defense
Council; Environmental Defense
Fund)
George P. Green
(Public Service Co. of Colorado)
Joseph J, Brecher
(representing Pacific Gas and
Electric Company)
J. Kenneth Robinson
(U.S. House of Representatives)
Frank Moore
(Asst. to the President)
and
John C. Stennis
(U.S. Senate)
and
Donald C. Lutken
(Mississippi Tower and Light)
Paul Simon
(U.S. House of Representatives)
2-47
-------
TABLE 2-1 (Continued)
No. Docket Ho. Comenters
605 D-637 Frank Moore
(Asst. to the President)
and
Thad Cochran
(U.S. House of Representatives)
and
V. J. Daniel, Jr.
(Mississippi Power Company)
606 D-638 John Tower
(U.S. Senate)
and
Philip D. English
(Broventure Company, Inc.)
607 D-639 Lloyd Bentsen
(U.S. Senate)
608 D-640 Lawton Chiles
(U.S. Senate)
and
Norman 0. Stern
(American Lung Assn. of Broward-
Glades-Hendry, Inc.)
609 D-642 Matthew F. McHugh
(U.S. Representative)
and
E. Eugene Forrest
(New York State Electric and
Gas Corporation)
'610 D-643 Robert L. Livingston
(U.S. House of Representatives)
611 D-644 Robert R. Wohler
(WAHLCO)
612 D-645 Elizabeth Johnson
(Coalition for the Environment)
613 D-646 Wilma T. Kennell
(U.S. Resident)
614 D-648 Thomas A. Vanderslice
(General Electric Company)
2-48
-------
No.
615
TABLE 2-1 (Continued)
Docket No, Commenters
616
617
618
619
620
621
622
623
624
625
626
D-649
D-650
D-651
D-652
D-653
D-654
D-655
D-656
D-657
D-658
D-659
D-660
Ray Thornton
(U.S. House of Representatives)
and
Arch P. Pettit
(Arkansas Power and Light Co.)
H. T. Johnson
(U.S. House of Representatives)
Scott Matheson
(Governor of Utah)
Pamela Zinn
'(The White House)
and
John R, Hamann
(Detroit Edison)
Gus Yatron
(U.S. House of Representatives)
J. Hemandez-Fragoso
(Puerto Rico Water Resources Authority)
Meg Titus
.(League of Women Voters)
R. L. White
(Texas Utilities Generating Co.)
M. 'P. Lanahan
(N.Y. Dept. of Environmental
Conservation)
Arlan Stangeland
(U.S. House of Representatives)
and
James L. Grahl
(Basin Electric Power Cooperative)
Liz Stajduhar
(U.S. Resident)
William W. Scranton, III
(Lt. Governor, State of Pennsylvania)
2-49
-------
TABLE 2-1 (Continued)
Mo. Docket No. Comnenters
627 D-661 M. Ardell
(U.S. Resident)
628 D-662 Ted Stevens
(U.S. Senate)
and
R.L. Hufman
(Golden Valley Electric Assn.» Inc.)
629 D-663 M. Diana Gyllenhammar
(U.S. Resident)
630 D-664 B. G. Myott
(Montana Power Co.)
631 D-665 J. M. Carroll
(Governor of Kentucky)
632 D-666 Mary Lynn
(U.S. Resident)
633 B-667 Thad Cochran
(U.S. Senate)
and
John R, Craft
J. Stewart Frame
Thomas A. Dallas
(U.S. Residents)
634 D-668 Patricia Senft
(U.S. Resident)
635 D-669 Milton R. Young
(U.S. Senate)
and
James L. Grahl
(Basin Electric Power Cooperative)
636 B-67Q Richard E. Hug
(Environmental Elements Corp.)
637 D-671 J. J. Brecher
(U.S. Resident)
2-50
-------
TABLE 2-1 (Continued)
No_._ Docket No. Conmenters
638 D-672 Ken Kramer
(U.S. House of Representatives)
and
John J. Bugas
(Colorado-Ute Electric Assn., Inc.)
639 D-673 W. E. Stepheason
(Paluszek & Leslie Associates)
640 D-674 - Graham H. Tempel
(U.S. Resident)
641 D-675 April Sanders
(U.S. Resident)
642 D-676 David Pryor
(U.S. Senate)
and
Arch Pettit
(Arkansas Power & Light)
643 D-677 Trent Lott
(U.S. House of Representatives)
and
J. Stewart Frame
(U.S. Resident)
644 D-678 John A. Durkin
(U.S. Senate)
and
Russell A. Holden
(New England Power Company)
645 . . D-679 John C. Stennis
(U.S. Resident)
and
David J. Bridgets
(U.S. Resident)
646 D-680 Mark Andrews
(U.S. House of Representatives)
647 D-681 Thad Coehran
(U.S. Senate)
and
David S. Bridgers
(U.S. Resident)
2-51
-------
No.
648
649
650
651
652
653
654
655
656
TABLE 2-1 (Continued)
Docket No, Commenters
D-682
D-683
D-684
D-685
D-686
D-687
B-688
D-689
D-690
John Glenn
(U.S. Senate)
and
LeRoy S. Harris
(The American Society of
Mechanical Engineers)
Barry Goldwater
Dennis DeConcini
(U.S. Senate)
Dick Cheney
(U.S. House of Representatives)
J. James Exon
(U.S. Senate)
and
James L. Gjrahl
(Basin Electric Power Cooperative)
Virginia Smith
(U.S. House of Representatives)
and
James L. Grahl
(Basin Electric Power Cooperative)
Lester L. Wolff
(U.S. House of Representatives)
and
Lellani Zutrau
(U.S. Resident)
Catherine Roberts
(Planning Office of Crested Butte,
Colorado)
Richard Schwelker
(U.S. Senate)
and
Vincent Makowski
(Solicitor, Borough of Marion
Heights, Pennsylvania)
Gus Yatron
(U.S. House of Representatives)
and
William Wickert, Jr.
(Bethlehem Steel Corporation)
2-52
-------
TABLE 2-1 (Continued)
No. Docket Ho. Commenters
657 D-691 M. Child
(U.S. Resident)
658 D-692 Not a comment letter
659 D-693 Not a comment letter
660 D-694 John J, Rhodes
Bob Stump
Eldon Rudd
(U.S. House of Representatives)
661 D-695 Richard S. Schyeiker
(U.S. Senate)
662 D-696 Not a comment letter
663 D-697 C. Oliver
(U.S. Resident)
664 D-698 G.C. Freeman, Jr.
(Hutton & Williams)
665 D-699 Utility Air Regulatory Group
(UARG)
666 D-70Q G.C. Freeman, Jr.
(Hutton S Williams)
667 D-701 Not a comment letter
668 D-702 Paul S.- Sarbanes
(U.S. Senate)
and
Richard E. Hug
(Environmental Elements Corp.)
669 D-703 J.E. Bicker
(McCone WIFE)
670 D-7Q4 N.D. Grasmehr
(League of Women Voters of
Centura County)
2-53
-------
No.
671
672
673
674
675
676
677
678
679
680
681
682
683
684
TABLE Z-I (Continued)
Docket No. Com enters
D-705 R. Guenther
(U.S. Resident)
D-706 J,B. Roy
(U.S. Resident)
D-707 Tennyson Guyer
(U.S. House of Representatives)
D-708 M.W. Steinberg
(U.S. Resident)
D-709 E,R. Edle
(South Dakota Resources Coalition)
D-710 • J. Dembeck
(U.S. Resident)
D-711 Y. Maxots
(The Planning and Conservation League)
D-712 B. Rutemoeller
(U.S. Resident)
D-713 1. Copley
(U.S. Resident)
D-714 N. Macy
K. Macy
(U.S. Residents)
D-715 L. Solomon
(U.S. Resident)
D-716 Charles McC. Mathias, Jr.
(U.S. Senate)
and
Richard 1. Hug
(Environmental Elements Corp.)
D-717 , S. McAvoy
(Illinois Environmental Council)
D-718 S. Gayner
(U.S. Resident)
2-54
-------
No.
685
686
687
688
689
690
691
692
693
694
695
696
697
698
TABLE 2-1 (Continued)
Docket No. Commenters
D-719 P.G. Robinson
(Southwest Environmental Service)
D-720 E. Rosen
(U.S. Resident)
D-721 L. Sprague
(U.S. Resident)
D-722 T. Dobson
(Public Interest Research Group
in Michigan)
D-723 P, Haworth
(U.S. Resident)
D-724 P, Stuart
(Powder River Basin Resource Council)
D-725 George C. Freeman, Jr.
(Hutton & Williams)
D-726 A. Bruno-Vega
(Puerto Rico Water Resources Authority)
D-727 C.R. Feldman
(Americans for Energy Independence)
'D-728 L. Lewis
(Sierra Club, Grand Canyon Chapter,
Arisona)
D-729 D.F. Weiss .
(U.S. Resident)
D-730 E. Sonoga
(U.S. Resident)
D-731 Not a comment letter
D-732 Robert H. Michel
(U.S. House of Representatives)
and
Illinois Power Company
2-55
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No.
699
711
TABLE 2
Docket No.
D-733
700
701
702
703
704 •
705
706
707
708
709
710
D-734
D-735
D-736
D-737
D-738
D-739
D-740
D-741
D-742
D-743
D-744
D-745
712
D-746
-I (Continued)
Comaenters
Thad Cochran
(U.S. Senate")
and
G. Adam
(U.S. Resident)
Not a comment letter
R.L. Emrlch
(First Presbyterian Church of
Greensburg, PA)
Not a comment letter
Not a comment letter
Unsigned
(U.S. Resident)
Not a comment letter
K. Katzenstein
(U.S. Resident)
Not a comment letter
John Melcher
(U.S. Senate)
R. J, Rauch
(Environmental Defense Fund)
G.C. Freeman, Jr.
(Hunton & Williams)
Paul Simon
(U.S. House of Representatives)
and
H.L. Deakins
(Illinois Power Company)
Dale Bumpers
(U.S. Senate)
2-56
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TABLE 2-1 (Concluded)
No. Docket No. Commenters
713 D-747 5. Flanigau
(U.S. Resident)
714 D-748 Not a comment letter
715 D-749 E.D, Fillmore
(League of Women Voters of
Southeastern Pennsylvania Region)
716 D-750 C. Frisch
N. Lederer
(League of Women Voters of
Detroit)
717 D-751 E.J. Stanek
I.E. Crane
(Iowa Energy Policy Council)
718 D-752, R.E. Hug
(Environmental Elements Corp.)
719 D-753 F. Beal
D.J, Goodwin
(Illinois Institute of Natural
Resources)
720 D-754 H.I. Bond
(Atlantic Richfield Company)
721 D-755 J.R. Thompson
(State of Illinois, Office of
the Governor)
722 D-756 C.E. Bagge
(National Coal Assn.)
2-57
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TABLE 2-II
LIST OF PERSONS PRESENTING TESTIMONY AT THE PUBLIC HEARING
No_. Docket_ No. Commenters
1 F-laa Walter Markey
(Gilbert Commonwealth)
2 F-lb John W. Ross ,
(Montana Power Co.)
3 F-lbb Leonard V. Ziolkowski
(Economic Development Council)
4 ' F-lc Joseph F. Brecher :
(representing The Sierra Club)
5 F-lcc William Savinsky
(United Mine Workers of America)
6 F-ld James McCarville
(City of Superior, Wisconsin)
7 F-ldd Robert Lazarchik
(Joint Authority Committee)
8 F-le Al Johnson
(Johnson Brothers Corporation)
9 F-lee George Gensemer
(SEDA - Council of Governments)
10 F-lff Frank Zukas
(Greater Pottsville Area Chamber
of Commerce)
11 F-lg George Greene
(Public Service Company of
Colorado)
12 F-li Carl M. Shy, M.D.
(American Lung Association)
13 F-lj Meg Titus .
(League of Women Voters of the U.S.)
14 F-ll Reverend Bruce Tischler
(Joint Program Agency of Lehigh
and Lackawanna Presbyteries of the
United Presbyterian Church)
2-58
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TABLE 2-II (Concluded)
No. Docket _No. Comnenters
15 F-ln Robert Rauch
(Environmental Defense Fund)
16 F-lo Daniel Schwartzman
(Health Resources Management,
University of Illinois,
School of Public Health)
17 F-lq Thomas G. Healy
(National Coal Association)
18 p-lr William Albers
(Appalachian Regional Commission)
19 F-ls B. G. Codec
(Utilities of the City of
Colorado Springs)
20 F-lt Richard Ayers
(NRDC)
21 F-lu George C. Freeman, Jr.
(Utility Air Regulatory Group)
22 F-lw John R. McNamara
(Power Salt River Project)
23 F-lx Raymond E. Kary, Ph.D.
(Arizona Public Service Corp.)
24 • p_iy Dennis Eyre
(Western Systems Coordinating
Council)
25 F-lz Ixwin Tucker
(Professor, Univ. of Louisville)
26 F-2 George P. Green
(Public Service Company of
Colorado)
27 F-3 Allen E, Ertel
(U.S. House of Representatives)
2-59
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TABLE 2-III
LIST OF OFFICIAL WRITTEN COMMENTS FROM
OTHER FEDERAL ORGANIZATIONS
No. Docket No. Commenters
1 H-5 William V. Skidmore
(General Council of Commerce)
2 H-6 Deputy Assistant Secretary
(United States Department of
the Interior)
3 H-8 Acting Director of the National
Park Service
4 H-9 S. David Freeman
(Tennessee Valley Authority)
5 H-10 John F. O'Leary
(Department of Energy)
6 H-ll Cecil D. Andrews
(U.S. Department of the Interior)
7 H-12 Barry P, Bosworth
(Council on Wage and Price
Stability)
8 H-13 William V. Skidmore
(General Counsel of the U.S.
Department of Commerce)
9 H-14 • Daniel Badger
(Department of Energy)
10 H-15 Jerry Pell
(Anthracite Division, Office of
Coal Supply, Dept. of Energy)
11 . H-17 John.P. O'Leary
(Department of Energy)
12 H-19 Bob lergland
(Department of Agriculture)
2-60
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2.2 Administrative and Procedural Actions
1. D-231
Comment: On page 42117 Section 60.40(a)(3) should read "(3) Not
subject to."
2. D-231
Comment: On page 42180 in the formula for Fj there should be a
plus sign instead of a multiplication sign at 35.4 (%S) x
8.6 UN).
3. D-231
Comment: On page 42182 the formula for Fw is missing a plus (*)
sign between 0,14(%R) and 0.46(%0).
4. D-203
Comment: The formula for determining the NOX standard for mixed
fuels in section 6Q.44a-(d) is missing an "equals" sign be-
tween PS{gQx and w(86),
5. D-417
Comment: Evaluation of costs and non-air quality impacts have not
been done with regard to oil-fired unit regulations.
6. D-461
Comment: NOX and particulates have fuel specific regulations
while SC>2 has a single uniform regulation. This appears
to be inequity in the uniform approach.
2-61
-------
7. D-626
Comment: Adequate opportunity to review all the data has been pro-
vided by EPA.
8. D-628
Comment; A riurabe'r of procedural comments regarding the data
published in the Federal Register for the first time on
December 8, 1978 are:
* How can a response be made to data which may not be re-
liable because EPA's technical staff has not verified
it?
» There is an inconsistency in the description of the
sixth alternative between the subtitle section "Sliding
Scale with 90 percent Control in West" and the discus-
sion following which describes 50 percent control.
* Are the 3 alternatives - 95 percent S02 reduction, 90
percent reduction, and seven options for' partial scrub-
bing - designed to support the September proposals or
are they new control proposals in themselves?
* The required economic and energy assessments mandated
by Section 307 of the Clean Air Act Amendments have not
been provided for the new alternatives presented in the
December addendum.
* In the December information, costs of complying with
various alternatives were combined into one cost figure
so that the economic effect of costs for S02, NOX
and particulates standards cannot be separately
considered or responded to.
9. D-491, D-629, D-698
Comment: Under section 307(d) of the Clean Air Act, EPA is required
to provide adequate opportunity for public review and com-
ment on proposed rules. Based on the relative importance
2-62
-------
of this standard, insufficient time was allotted for
public comment*
10. D-491, F-lu
Comment: Under section 307(d) of the Glean Air Act, EPA has an ob-
ligation to disclose fully at the time it publishes a
proposed NSPS the entire record upon which it bases its
proposal. EPA has failed to comply with these require-
ments. This could have the effect of legally invali-
dating the entire rulemaking procedure.
11. D-491
Comment; The public hearing held on December 12-13 should have
provided the public with an opportunity to explore the EPA
background and rationale for the proposed standard. In-
stead the hearing disclosed the bases for the positions
taken by all participants except EPA, the only participant
with a statutory obligation to disclose its basis.
12. D-743
Comment: A method to prevent ex parte communications is presented
for consideration.
13. B-753
Comment; EPA has failed to provide adequate and timely information
to potentially affected parties.
2-63
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2,3 Affected Facility
2.3.1 - 60.40a Applicability and Designation of Affected Facility
General Comments on Applicability
1. D-4Q9
Comment; The proposed regulations create a "double standard" by
not covering all fossil fuel fired steam generators. Only
electric utility plants are covered by the proposed
standard, Commenter questions legality of this under
Section 111 of Clean Air Act.
2. D-490
Comment: The unit size threshold should be established as 1250 x
106 Btu/hr instead of 250 x 106 Btu/hr due the hard-
ship imposed on small utilities.
2-64
-------
Combined Cycle Facilities
1. D-253
Comment: Only total stack emissions should be regulated in combined
cycle facilities rather than turbine emissions under a
separate subpart and boiler emissions under subpart Da as
proposed.
2-65
-------
Cogeneration Facilities
1. D-280
Comment: The regulations discriminate against cogeneration. Units
producing less than 25 MWe for commercial use should be
: . , jexempt regardless of capacity of boiler. ; .
2. D-412, D-423
Comment: The interpretation of the definition of "Electric Utility
Steam Generating Unit" as applied in the preamble is a
misinterpretation of the definition because,
* the interpretation of electric cogeneration units is
not in keeping with the categorization of boilers in
power plants as opposed to industrial plants as given
in Section 111 of the Clean Air Act.
• the interpretation of electric cogeneration unit fails
to take into consideration the second sentence of the
definition of electric utility steam generating unit
which if applied would increase the electrical energy
output of the cogeneration plant for purposes of de-
termining the percentage of electricity sold to the
public
* the proposed rules provide a credit for pretreatment of
fuel to remove sulfur or increase its heat content; yet
2-66
-------
the interpretation fails to take into account the high-
er utilization of the heat content of the fuel in the
cogeneration plant compared to the power plant
• the Interpretation unduly expands the meaning of "sale"
found in the definition. Many units use an accounting
system of "selling" all the electricity produced to a
grid and then "buying" electricity from the grid for
in-house use
3. D-448
Comment: The regulation is too restrictive for emerging technology
(e.g., the proposed NSPS would kill a project to use a
calcining kiln to generate 70 MWe).
4. D-460
Comment: Two identical boilers, one used for industrial and,in—
plant electrical generation, the other used for commercial
electric generation will have different standards, dis-
- criminating against utilities. This will cause an
increase in in—plant electrical generation and increased
pollution.
5. D-49Q
Comment: Cogeneration and alternate fuels should be exempt from
regulations or the threshold of applicability be raised
(no suggested level given). This would encourage use of
this energy efficient process.
2-67
-------
Resource Recovery Facilities
1. D-Z8
Comment: Refuse derived fuel should be included under the standard
since there is no difference between sulfur in coal and
sulfur in refuset
2. -D-259, B-449, D-490
Comment: Refuse derived fuel should be exempt to encourage
development of such usage.
- 3. D-423
Comment: All resource recovery units should be exempt from S02
percentage removal requirement In order to encourage use
of these fuels.
4. D-483
Comment: The current NSPS specifically exempts units modified to
use non-fossil fuel but proposed regulations do not. This
provision should be included.
5. D-595
Comment: The proposed standards should not be made applicable to a
new solid waste processing plant from which steam
and electricity would be sold to the U.S. Naval shipyard
in Portsmouth, Va. Boilers will normally be fired with 97
percent refuse derived fuel and 3 percent coal although
•under most conditions up to 21' percent coal might be
burned a few days per year. The plant would be
2-68
-------
jeopardized by cost of scrubbers and lack of space to
aeeomodate them on the available property. Making
standards applicable to plant would frustrate innovative
technology addressing energy and solid waste problems.
2-69
-------
Commenced Construction
1. D-33
Comment; The regulation should be extended to include existing
plants.
2. D-370
Comment: Clarification is needed to show that the regulation does
not apply to existing planes or plants clearly, under
construction.
3. D-153, D-463, F-16
Comment; The applicability section which designates September 18,
1978, as the specific cutoff date for commencement of con-
struction or modification should be amended to create a
reasonable transition period for those facilities which
received all necessary design and preconstruction ap-
provals, including current NSPS, SIP and PSD review.
Failure to allow this transition would have severe
inflationary impacts if time delays and/or redesign or
rereview of plans becomes necessary.
4. D-585
Comment": We believe that administrative due process- requires the
applicability of the regulations to be readily de-
terminable. The proposed regulations did not include any
2-70
-------
discussion of what act or acts constitute "commencement of
construction." We favor a precise applicability defini-
tion that would include either:
* commitment to a site
* purchase of a major component
2-71
-------
Modification
1. D-280, B-203, D-204
Comment: Preamble discussion on modifications (pg 42158) is not
reflected in regulations.
2. D-369
Comment: Modification which consists solely of installation of flue
gas cleaning equipment should not be considered to be an
NSPS modification.
3. D-224, D-404
Comment: Older gas—fired units forced 'to fuel switch due to gas
shortages should not be considered to be an NSPS
modification.
4. D-259, D-628
Comment: A. clearer description of modification should be given so
that energy conservation upgrading is not penalized.
5. D-397, P-lb
Comment: The standard should Include a statement that if a change
In a facility or its pollution control equipment would
result in less emissions being discharged into the
atmosphere or improved ambient air quality, such change is
not considered a modification.
2-72
-------
6. D-467
Comment; Modification of oil or coal units to burn wood and refuse
derived fuels should not be considered as an NSPS mod-
ification. This change would encourage conversion to
these alternate fuels.
2-73
-------
2.3.2 - 60.41a Definitions
Electric Utility Steam Generating Unit
1. D-153
Comment: If industrial boilers are exempt, small utility (e.g., LOO
MM) should be also.
2. D-467, D-491
Comment: The term "steam generating unit" is defined in section
60.41a(a5 to exclude nuclear steam generators. This is
inconsistent with section 60i41a(k) where the term "steam
electric generating unit" specifically includes nuclear
power plants. Removing the word "steam" in section
60.41a(k) would alleviate the inconsistency.
.2-74
-------
Utility Company
1. D-223
Comment: The definition of "utility company" should be clarified to
distinguish it from an "owner or operator" as defined at
60.2(f). For example: "utility company" as applied to
the determinations of the existence of an "emergency con-
dition" means the largest organization, business, or
governmental entity that owns the affected facility (e.g.
a holding company with operating subsidiary companies).
2-75
-------
System Capacity
1. D-253, I>-491
Comment: The present definition excludes hydroelectric and geother-
mal power,
2. D-413
Comment: The definition should ensure that net plant capacity
and not rated capacity is used to determine whether or not
an emergency exists.
3. D-491
Comment: The definition of system capacity (section 60,41a(j))
should include firm contractual purchases and should ex-
clude firm contractual sales. The following change Is
suggested to the last sentence,
"The electrical generating capacity of electric generating
equipment under multiple ownership is prorated based on
ownership unless the proportional entitlement to electric-
ity generated by that capacity Is otherwise established
by contractual arrangement."
2-76
-------
System Emergency Reserves
1. D-253
Comment: The definition appears to refer to the largest single unit
in the system, but it is not clear whether or not the unit
is on-line and carrying load. Suggests it should be the
largest on-line unit that is considered the largest unit.
2. D-413
Comment: The definition should account not only for the capacity of
the single largest generating unit, but also for reserves
needed for system load-frequency regulations.
3. ,D-491
Comment: Under 60.41a(k) the last sentence should be modified to
read,
"The electrical generating capacity of electric generating
equipment under multiple ownership is prorated based on
ownership unless the proportional entitlement to electric-
ity generated by that capacity is otherwise established
by contractual arrangement."
2-77
-------
Available System Capacity
1. D-467
Comment: The definition of available system capacity should be
modified to read "the capacity determined by subtracting
the sys.tem load, the system emergency reserves, firm
transactions, and unit power commitments 'from the system
capacity." This change will take into- account capacity
which is owned by one utility but committed for use by
contract to another utility upon conditions which prohibit
the electricity sold from being withdrawn. Such
electricity is unavailale to the selling utility for the
life of the contractual arrangement.
2. D-491
Comment: Some utilities have certain localized areas or zones
within the general areas which they service which, due to
system operating parameters, cannot be served by all of
the generating units which constitute the utility's system
capacity. As a result, an affected facility may be the '
only source of supply for a zone or area even though there
is one capacity in the system. The proposed regulations
should explicitly allow deduction from system capacity of
any capacity which cannot be used to meet system load in a
particular area or zone.
2-78
-------
Spinning Reserve
1. D-491
Comment: Under paragraph 60,41a(ra) the last sentence should be
modified to read,
"The electrical generating capacity of electric generating
equipment under multiple ownership is prorated based on
ownership unless the proportional entitlement to electri-
city generated by that capacity is otherwise established
by contractual arrangement."
2-79
-------
Emergency Condition
1. D-253
Comment: The paragraph title should be reworded to "Flue Gas
Desulfurization Emergency Conditions" to distinguish from
electrical system emergencies.
2. D-253
Comment: It would appear that a utility would have to shut down a
unit with a malfunctioning FGD module if there were other
units down for fuel conservation or in cold storage. It
is suggested that this section be changed to read: "one
or more electric generating "units held in spinning reserve
or cold standby reserve, or ..."
3. D-320
Comment: Emergency bypass conditions for sulfur dioxide scrubbers
should be determined by the number of units on line at the
time of the emergency occurrence.
4. D-373
Comment: The load switching requirement makes oil or gas-fired
generators a control technology.
5. D-404, D-417, D-437
Comment: EPA should recognize that factors in addition to equipment
malfunction (e.g., lack of fuel) can limit the availabil-
ity of a generating unit.
2-80
-------
6. D-4Q9
Comment: In Che absence of emergency conditions, a facility with a
malfunctioning FGD system should be exempt from the per-
cent reduction requirement if it cannot be met. The max-
imum limit of 1.2 lb/10& Btu would still apply,
7. D-413
Comment: The regulations do not allow for the severity of a
malfunction. Partial failure of a FGD should be
compensated for by limiting generation from the affected
units and not removing them from service.
8. D-413, D-447
Comment: The regulations should give consideration to the
possibility that an emergency may occur shortly after an
affected unit is removed from service.
9, D-459
Comment: Justification for the three 24-hour exemptions of the 85
percent reduction requirement is not given in the back-
ground document.
10. D-467
Comment: This definition has not been defined broadly enough to en-
compass potential emergency situations associated with the
generation, transmission and distribution of electricity.
At a minimum the definition should be modified to include
long term fuel shortages as well as short term capacity
2-81
-------
shortag.es in neighboring utility systems where a system
voltage reduction would result i£ the scrubber could not
be bypassed*
11. D-486
Comment: Present requirements for emergency conditions may produce
negative results by forcing use of.uncontrolled peaking
units. Recommend a. grace period upon failure of control.
12. D-491
Comment: The standard should recognize that a utility may need to
keep a unit in operation (or bring a unit on line) because
an emergency condition is projected for that day or the
next calendar day. The orderly startup or shutdown of a
unit requires up to eight to twelve hours under some
conditions. To allow for this "look ahead," section
60.41a(n) should be changed by adding the following words
at the end of section 60,41a(n)(1):
"when such conditions are projected to occur at any time
through the next calendar day."
2-82
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2.3.3 - Special Issues
Anthracite Coal
1. D-21, D-803 D-259, D-326, D-343, D-402, D-4G9, D-419, D-420,
D-422, D-42i, D-444, D-465, D-511, D-554, D-573, D-578, D-584, D-587,
D-602, D-606, D-607, D-653, D-660, D-695, D-735, F-la, F-ll, F-lr,
F-lcc, F-ldd, F-lee, F-lff, H-10, H-15
Comment; Anthracite coal should be exempt from S02 regulations or
a special standard established because:
0 natural low sulfur content will have little impact on SC>2
emissions
* btandard would encourage use of high sulfur coal
e reopening and reclamation of anthracite mines would encourage
or require strict land reclamation which, is beneficial and
will result in cleaning up of culm piles
• economic .benefit to- anthracite region
• unproven controls on anthracite
• other fuels (e.g., lignite) have related standards
a since NOX standard does not mention anthracite, precedent
for exemption already exists
* less stringent standard will permit anthracite to compete
with other sources of coal which are cheaper to mine
* would produce no more SC>2 emissions with exemption from
scrubbing than high sulfur bituminous coal with full
scrubbing
» anthracite is at a competitive disadvantage because it is al-
most entirely obtained from deep mining of previously worked
areas
* improved water quality as a result of alleviating existing
acid-mine drainage problems
2-83
-------
• improved safety as a result of eliminating subsidence prob-
lems
2. D-343
Comment: The standard unfairly precludes the use of anthracite
3. D-134, F-3
Comment: Full scrubbing is economically disadvantageous to anthra-
cite coal.
4. D-122
Comment: Contrary to popular belief, the averge sulfur content of
Pennsylvania anthracite coal is 1.09 percent, which would
not meet NAAQS. (presents survey data)
5. D-439, D-551, D-729
Comment: Anthracite coal should not be exempt because:
* drilling data (1977) indicates sulfur content at 1.1% S
* uncontrolled emissions would exceed 1.2 lb/10^ Itu
6, D-487, D-610
Comment: The standard for anthracite coal should be 1,0 Ib SC>2/
10& Btu (floor) in order to:
• improve water quality in region
* reduce subsidence
* encourage reclamation and restoration of abandoned mine areas
• stimulate anthracite industry
* increase employment
* increase water supply
2-84
-------
7. D-552
Comment: Problems which these proposed regulations present for
utilities burning "both anthracite and western
sub-bituminous coal, though not identical, are similar.
Anthracite is in fact a "local" coal. Western
sub-bituminous will be used In many areas where there is in
fact no "local" coal. Thus, under the Act, the fuel
characteristics of both coals might be taken into
consideration in establishing percentage reduction
requirements for steam generating units in certain
geographic market areas.
8. H-15
Comment: Anthracite has more problems with particulates than do
other types of coal. Therefore anthracite coal must
continue to meet all particulate standards, even if
scrubbers for S02 should not be required under special
provisions of the standard applicable to anthracite.
9 P-la
Comment: The State of Pennsylvania has an ongoing large-scale
project for massive reclamation and rehabilitation at
several abandoned anthracite sites proposed for reopening.
One area involves 12,000 to 19,000 acres of despoiled land.
Financial resources are already being assembled to cover
costs at the first site. This effort indicates clearly the
potential environmental gains which are possible if a
2-85
-------
federal incentive such as exemption of anthracite coal from
the SC>2 standard Is provided.
2-36
-------
Noncontinental Areas
1. D-159, D-366
Comment: Noncontinental U.S. should be exempt from the S02
standard for cost/benefit reasons,
2. D-283
Comment: Section 6Q.43a (c)(2) should be changed- to include "and has
to the satisfaction of the Administrator demonstrated that
there is no alternative to using oil as fuel."
3. D-574
Comment; Non-continental areas should be exempt from the St>2
standard- because:
* limited land area for sludge disposal
• Puerto Rico population density of 900 persons/square mile
» can use "low sulfur coal to replace oil
•* unique meteorological conditions for atmospheric dispersion
without ground-level increase in S02 concentration
4. D-726
Comment: If EPA considers lowering the ceiling to less than 1.2
lb/10" Btu, they should be aware that this will negate
any exemption from the 85% reduction requirement because
the lower emission ceiling will require scrubbing.
2-87
-------
Alaskan Coal
1. D-150, D-366, D-520, D-562
Comment: Alaskan coal should be exempt from the S02 standard
because:
• Alaskan coal is 0.25 percent sulfur
• Economics of lime transportation
* Sludge disposal
• technology is incapable of removing 85 percent of sulfur from
0.25 percent sulfur coal
• difficulties of operating wet scrubbers and disposing of
sludge with ambient temperatures of 50°F below zero.
• utilities burning high sulfur coal could comply with proposed
regulations and still emit substantially more S02 than
Alaskan coal with no removal whatsoever.
2. D-608
Comment: Heavy media washing of the Western subbituminous coals from
Golstfip County; Montana, may yield a coal also unique in
its low sulfur content and reduced ash content. This coal
could also be a. candidate for the less stringent standards
being considered for anthracite and Alaska coal.
3. D-631
Comment: Exempting Alaskan plants from the percentage reduction
would be illegal under the uniform percentage reduction
provision of the law. Therefore it should not be done.
2-88
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4. D-562
Comment: Alaskan coal should be exempt from the SC>2 standard. The
proposed rationale for exempting Hawaii should be extended
to Alaska, The Alaskan airshed, fuel supply5 electrical
grid and transportation network are not common to the rest
of the United States.
2-89
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Emerging Technology
1. D-50, D-168, D-216, D-255, D-315, D-343, D-418, D-491
Comment: The requirement for FGD discourages alternate technology
development because;
D-343; multi-stream coal cleaning is precluded
D-255; use of biomass fuel is precluded
D-50; proposed granting exemptions on case by case basis
D-491; SRC, dry scrubberss fluidized bed combustion are pre-
cluded
2. D-223, D-369, D-245, D-259
Comment: The regulations do not address the development of
innovative pollution control technology (for example, dry
scrubbing not listed).
3. D-280
Comment: The standard should state 15,000 MW at 70 percent load to
adjust for various load factors
4. D-280
Comment: The standards establish a minimum allocation for any other
technique not specifically mentioned
5. D-280
Comment: SRC I should be under solvent refined coal and not coal
liquefaction
2-90
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6. D-280
Comment: The preamble should not limit number of demonstrations
since the standard does not.
7. D-280
Comment: An additional section 60«45a{e) should be included: If
technology is not working, plant must meet 0.8 lb/10^ Btu
(e.g., start up, malfunction, etc.)
8. D-280
Comment: The standard should provide that the 80 percent reduction
allowed in Section 60.45a will be calculated in the same
manner as the overall standard for regular power plants,
Including quarterly averaging when the emerging technology
Involves fuel pretreatment.
9. D-280
Comment: The preamble suggests that Section 60.45a only concerns
bituminous coal
10. D-373
Comment: "Emergency Technologies" should include alternative tech-
nologies on page 42160.
11. D-413, D-455, D-585, H-10
Comment: The proposed emerging technology provisions are appropriate
and should be adopted.
2-91
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12. D-608
Comment: Provisions for commercial demonstration permits should be
expanded to include pre-eombustion coal cleaning tech-
nologies such as heavy media washing and chemically clean-
ing.
13. D-631
Comment: The entire concept of relaxed regulations for innovative
technology demonstration is illegal. EPA's authority to
gubcategorze in this manner is allowable under section
111( jKD (A) (ii) only if the technology is likely to
achieve emission reductions equal to or greater than the
levels designated "beat"*
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2.4 Emission Limits
2.4.1 60.42a Standard for Particulate Matter
General Comments on Participates
1. D-274, D-289, D-329
Comment: The emission limit should be as strict as possible in
order to insure public health and environmental quality^
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Particulate Emission Limit
1.- D-211, D-229S D-250, B-268, D-413, D-462, D-505, H-8
Comment: The proposed emission limit is correct or could possibly
be stricter. This position was stated either without
reason or based on the opinion that adequately
demonstrated control technology can achieve the limit of
13ng/J (0.03 lb/106 Btu).
2. D-170, D-285, D-300, D-406, F-ly
Comment: The proposed emission limit is not tight enough. This
position was stated either without reason or based on the
opinion that adequately demonstrated control technology
can achieve less than 13 ng/J (0.03 lb/106Btu).
3. D-167, D-168,, B-205, D-215, B-216, D-218, B-219, D-223, B-224,
D-227, D-231, D-234, D-256, D-259, D-266, D-271} D-315, D-322,
D-325, D-330, D-368, D-369, D-370, D-380, D-397, D-3983 D-399,
D-403, D-404, D-410, D-418, D-433, D-437, D-438, D-446, D-447,
D-448, B-451, D-4583 D-460, D-461, D-463, D-464, D-466, D-467,
D-471, D-473, D-475, D-47S, D-481, D-482, D-483, D-485, D-486,
D-488, D-489, D-490, D-491, B-519, D-585, D-M23 D-682, F-lb,
F-lg, F-ls} F-lx, F-2
Comment: The proposed emission limit is too strict. Many of these
commenters favor the positions adopted by DOE and/or UARG.
Many favor retention of the present standard of 0.1
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lbs/10° Btu. Reasons stated were one or several of the
following.
m The proposed standard is based on unproven technology and
cannot be achieved.
* The proposed standard cannot be achieved consistently over
the long term in a practical situation.
» "The standard would rule out a specific type of wet scrubber
with unique environmentally acceptable characteristics that
was designed for collecting fly ash from western coals and
that was used in Northern Plains states as a device to 'remove
SQ2- This procedure has enabled the consumption of energy
to be reduced by accomplishing two pollution-control jobs in
one step."
• The data are not sufficient to state scrubbing would not
increase particulate emissions.
* A standard of 0.05 lb/10^ Btu would allow scrubbers.
• A performance/acceptance test is not a true indication of
everyday performance.
• The standard entirely precludes the use of wet particulate
matter scrubbers.
* The only possible control technology (baghouse) is unproven
on large utilities.
* The standard unjustifiably discriminates against the elec-
trostatic precipitator.
• The proposed standard is highly inflationary.
• The benefit versus cost of the standard cannot be justified,
• Requirements should be set for health and environmental pro-
tection, not on highly expensive new technology.
• Reason unstated.
4. D-217, D-253
Comment: The proposed limit is unjustified for typical grades of
fuel oil. In order for fuel oil to be exempt from using
2-95
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controls an ash content of 0.015 percent by weight would
be required. If 0.02 percent by weight fuel oil were
used, controls would be necessary for removal of only
0.005 percent by weight of the fuel oil.
5. D-156, D-262, D-265, D-277, D-371, D-373, D-401, D-417, D-449,
D-477, D-574, D-621, F-lw, H-10
Comment: The emission limit should not be as strict as proposed,
Several values ranging from 0.05 Ibs to 0.08 lbs/106 Btu
were proposed, Ihis position was stated either without
reason or to allow the use of electrostatic precipitators
as one of the control options.
6. D-153, D-442, D-458
• Comment: Does EPA include particulates entrained from a wet
scrubber as part of the allowable emissions, or are they
exempt?
7. D-120
Comment: Favor the standard but the emission limit is unfair to
solid fuels and encourages coal liquefaction'which is- more
costly, energy intensive and inefficient.
* Standard seems to encourage use of oil.
* EPA should consider fuel mixtures for these situations.
8. D-153
Comment: The standard does not provide for soot blowing.
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9. D-369
Comment; Sections 60.42(a)(l),(2) ,(3) and 60.46a(a) are confusing.
Why have mandatory percentage reduction and not enforce
it?
10. D-313
Comment; The proposed standard is not strict enough. The
California South Coast Air Quality Monitoring District
requires, 6,018 lbs/106 Btu.
11. D-231
Comment: The standard for particulates "ignores the extreme paucity
of precipitator and scrubber data for lignite fueled power
plants in Texas. On the same page the NOX Standard
(last paragraph) discussion uses the same argument for re-
taining the current lignite NOX standard."
12. D-440
Comment: No credit is given for ash removal prior to combustion.
Suggest credit be made in paragraph 60.42a.
13. D-468
Comment: The standard should be rewritten to measure allowable emis-
sions in terms of mass of particulates per megawatt hours
of output. This will create an incentive for increased
conbustion efficiency.
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14. D-491
Comment: Bypass loops in conjunction with rapid switching dampers
are necessary and should be provided to prevent any sudden
reductions in boiler load level caused by fabric blinding
that might affect system reliabilityt Bypass would allow
boiler load levels to be maintained until safe reductions
could be made, consistent with local and network power
needs and proper emergency shutdown procedures. Bypass may
also be necessary to protect boiler components and the
baghouse itself.
15. D-627
Comment: The present NSPS for particulates provides a safety factor
of around 35 for public health, when maximum ground-level
concentrations resulting from a 500 MW plant are compared
with NAAQS. There is no advantage in increasing this
margin by the proposed reduction in allowable particulate
levels. Ambient concentrations will not be reduced be-
cause with the reduced emission rates, plants up to 16
times greater (8000 HW) can be built under FSD standards.
16. D-631
Comment: The particulate emission limit should be 0.01 Ibs per mil-
lion Btu with 99.5% reduction required. Technology to
achieve this has been adequately demonstrated.
2-98
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Best System of Emission Reduction for Particulates
1. D-168, D-224-, D-23a; D-267
Comment: Control technology for participates has not been de-
monstrated to the level required by the standard. No
specific reasons stated.
2. D-168, D-216, D-2273 D-2313 D-237, D-250, D-256, D-259, D-262,
D-300, D-315, D-320, D-322, D-141, D-426, D-444, D-458, D-491
Comment: Control technology for baghouses has not been demonstrated
to the level required by the standard, particularly on
large utilities. No specific reasons stated.
3. D-132, D-145, D-156, D-167, D-233, D-347, D-370, D-467, D-519,
D-523, D-642, D-657
Comment; Control technology for baghouses has not been adequately
demonstrated on large units. One or several of the fol-
lowing reasons were stated:
« No data are available on long-term life of bags.
• The problem of start-up temperatures was not adequately
analyzed.
• The possibility of bypass during start-up and process upsets
was not adequately addressed.
• Maintenance costs on large units were not properly assessed.
* Of 8 baghouses cited, 4 lacked data on type of filtration,
air-to-cloth ratio, cleaning method, and/or pressure drop.
Only 2 were on utility boilers. Only 3 are reverse air
cleaned. Only 4 clean entire systera. Only 2 burn pulverized
coal. None operate on full size systems (100-1000 MWe).
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4. D-153, D-247, D-263, D-274
Comment; The use of baghouses versus the sulfur content of the coal
has not been sufficiently analyzed.
5. D-223, D-400
Comment: Section lll(b) of the Clean Air Act prohibits requiring
any particular control system. The proposed standard is a.
de facto requirement to use a baghouse.
6. D-145
CommentJ It is not clear whether baghouses can be operated properly
on peaking units.
7. D-369
Comment: On page 17 of background document #10 listed in the pream-
ble to the proposed standards, it is stated that several
fabric filter manufacturers refused to guarantee meeting a
limit of 0,03 lb/106 Btu. However, EPA has proposed
such a limit.
8. D-268
Comment! Several fabric filter manufacturers will give written
guarantees of 0.004 lbs/10^ Btu at a price of $100 per KH
installed capacity. Therefore, EPA has not proposed a
strict enough limit.
9. D-145, D-205, D-227, D-464, B-467, D-491, D-519, F-lu
Comment: Control technology for ESPs has not been demonstrated to
the level required by the standard, particularly for long
2-100
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term consistent operation or for large pulverlzed-coal-
fired generating units,
* Of 21 tests, key data (recently conditioned, design values,
coal types (sodium content)) were missing on nine.
• In one case (Centralia 2) the ESP was actually 2 in series.
10. D-156, D-247, D-265, D-397, D-461
Comments The ESP should not be precluded from use with low sulfur
coal. No specific reason was stated.
LI. D-369, D-491
Comment: It is felt that EPA's tests on ESPs were done under ideal
conditions. Under practical operation much larger col-
lection areas would have to be used to guarantee meeting
the standard. This would make the ESP uneconomical.
12. D-223
Comment: No mention is made of manufacturer's warranties,
guarantees, etc. The user is held responsible.
13. D-253
Comment: No mention is made regarding whether or not EPA evaluated
the extent to which particulate removal techniques are
being used on low sulfur fuel oil fired burners. Nor was
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mention made of the possibility of achieving Che proposed
standard using low ash fuel alone•
14.- D-413
Comment: Estimates for ESP- size are underestimated. Suggest re-
evaluation of cost/benefit based on minimum ESP of 450-500
ft2/10QO ACFM Con 3.5% sulfur coal).
15. D-421, D-491
Comment: 'The participate limit precludes the use of two-stage
scrubbing as an effective control. EPA has effectively
"eliminated particulate scrubbing- as an option for
particulate control without adeq-uately examining, the
costs> the non-air quality environmental impacts, and the
energy requirements- associated with particutate scrubbing
in conjunction with SO? scrubbing. Based on the .
advantages and on the absence of an adequate analysis by
EPA as justification for precluding particulate scrubbing,
the revised particulate NSPS should be set at a level that
would allow the use o£ particulate scrubbing.
16. D-455
Comment: "There are precipitators which on any day will meet the
proposed 0.03 lb/10" Btu emissions standard. However,
precipitator performance can deteriorate rapidly because
of many reasons such as broken wires, control failures,
fuel variability, etc. In my opinion, long-term
2-102
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precipitator reliability is the basic question if total
' emissions are to be controlled. I would recommend a
gradual reduction, over a period of several years, of the
present 0.1 lb/10" Btu emission standard so that design
experience can be translated into workable solutions at
minimal expense."
17. D-491
Comment; EPA states that it considers SCA values of 650 to 1000
ft2/1000 ACFM to be reasonable for hot-side and cold-side
ESPSj respectively, considering such factors as cost and
energy. However, EPA has analyzed the cost of ESPs with
SCA values of only 650 ft2/1000 ACFM for a cold-side ESP.
Thus, EPA has provided no support for its conclusion that
ESPs of 650 SCA for hot-side ESPs and 1000 SCA for
cold-side ESPs can achieve the proposed standard at
reasonable costs.
18. D-491
Comment: EPA'has provided no information of the accuracy and overall
precision of Methods 5 and 17 or on the reliability of con-
tinuous opacity monitors. Information on the accuracy and
precision of the designated methods when used on electric
utility steam generating units at the 0.03 Ib/MBtu level
must be available before any conclusions can be drawn con-
cerning the validity of the test results cited by EPA as
2-103
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support for the proposed NSPS and any tests made to de-
termine compliance with the NSPS ultimately promul-
gated.
19. D-609
Comment: The adoption by EPA of NSPS less stringent than those which
one of the na.tion's largest utilities has agreed can be met
would be nothing short of irresponsible. Enclosed a
Stipulation re BACT from Pacific Gas and Electric Company
for proposed Fossil 1 and 2 power plant. BACT is defined
as:
• S02 - 951 removal, 24 hr. average
* PM - 0.003 gr/scf
• NOX - 0.45 Ib/mmBtu (possibly as low as 0.034 Ib/mmBtu)
20. D-631
Comment: EPA has overstated the costs of particulate controls.
Both the proposed EPA standard and the EDF/NRDC proposal
can be achieved at reasonable costs. Therefore, high cost
is not a valid criticism of a stricter standard.
21. D-631
Comment: Adequately demonstrated control technology exists which
has achieved emission limits of well below 0.01 ibs/10°
Btu. This includes both fabric filters and ESP's
operating on large units.
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22, D-631
Comment: The use of flue gas conditioning by the addition of sulfur
trioxide, ammonia, or triethylamine will significantly
improve ESP performance on some coals. This will allow the
use ofESP's to a greater extent than implied by the
background documentation.
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Adequacy of the Particulate Data Base
1. D-234
Comment: Insufficient data "were presented to conclude that bag-
houses are demonstrated.
2. D-252
Comment; EPA neglected to state an opinion on the efficiency of the
350 MW unit which recently began operation.
3. D-219, D-483, D-491, F-lb
Comment: EPA's data base is not adequate enough to support the pro-
posed standard for the following reasons:
* Only 44 percent of the EFA tests on control devices met the
standard (75 percent for baghouseSj 43 percent for ESP and 14
percent for scrubbers)
* Nine out of 21 ESP tests showing compliance does not con-
stitute demonstrated technology over an extended period.
* Of the eight baghouse tests, six were on stoker-fired boilers
and results were not transferable to pulverized units. Only
one of two tests on pulverized units was in compliance and
this was a small 44 MW unit. The standard should be based on
factual, demonstrated data, not unsupported opinions.
* Critical pre-test information necessary to evaluate and
interpret the performance of particulate control systems has
not been included in the EPA data base.
* SPA's background information contains virtually no
information on the cost-effectiveness of the proposed
particulate NSPS.
* EPA's data base is too small and incomplete to provide
sufficient statistical support for the proposed particulate
NSPS.
* EPA's data basej comprised of results froa a very limited
number of intermittent performance/acceptance and compliance
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tests, does not represent the performance of particulate con-
trol systems during day-to-day operation, including normal
variations caused by such occurrences as soot blowing and
load fluctuations.
4. D-369
Comment; The data and information used for determining control
technology performance for both baghouses and ESPs is
highly questionable. Background document EPA-45Q/2-78-
006a shows the following:
» Only 5 of 21 units listed in Table 4-2 met t,he proposed
standard.
* Three of the nine "best" units shown in Figure 4-14 could not
meet proposed standard.
• In Table 4-5 3 two of eight units with baghouses could not
meet proposed standard and largest tested was 44 MW.
• • .In total., only 9 of 21 units met the proposed standard,
5. D-317
Comment: In EPA's background information on scrubber particulate
.collection efficiency it is stated (Table S-3) that
Duquesne Lighting's Phillips and Elrama plants achieve
from 0.02 to 0.07 lbs/106 Btu. EPA fails to point out
that the equipment used in obtaining that data was a
heated probe with a glass wool collection device. The
method used was not EPA Method 5. As a result, the test
only represents collection of dust with no sulfates ac-
counted for. However, recent Method 5 tests on these uni-
ts, using similar coal, indicate that approximately one-
third of the total particulate leaving the scrubber system
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(0.03 lbs/10^ Ecu) is measured as aulfates. Thus even
if the' coal is completely flyash free or 100 percent of
the flyash is removed, a residual of 0.03 Ibs/lO^ Btu of
sulfate partlculates would be emitted. Thus, there is
little chance that the particulate standard can be met in
day-to-day operation.
6. D-443
Comment: EPA has failed to conduct sufficient analyses of particu—
late control on oil and gas units to establish a proper
foundation for such a strict standard.
7. D-461
Comment: The use of specific collecting area (SCA) as the sole de-
terminant of ESP efficiency is wrong. Other parameters
include: electrical sectionalization, size and number of
transformer and rectifiers sets, velocity, residence time,
sodium content, ash char, type and number o£ rappers, de-
sign of high volts and ground electrodes, temperature, dew
point and moisture content of gas, uniformity of gas flow,
and particle size distribution. Seeding may increase
particle sizes.
8. D-463
Comment: The effect of high altitude locations on baghouse air-to-
cloth ratios was not assessed.
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9. D-471
Comment: Montana Storm Units 1 and 2 were designed to meet 0.05
lb/106 Btu with a factor of safety. EPA results quoted
were acceptance test results and do not reflect continuous
operation or operation under load changes. The only way
0.05 lb/10^ Btu was met was with significant cverdesign.
This will be true for the 0.03 standard also.
10. D-167
Comment: The EPA test on Iowa Public Service's George Neal Unit #3,
which was used in the decision process, was ruled Invalid
by the Iowa Department of Environmental Quality. No ex-
planation given.
11. D-491
Comment: EPA's record contains no data on-the ability of lignite-
fired boilers to achieve the proposed standard and no re-
liable data on the ability of oil-fired boilers to achieve
the standard.
12. D-491 • '
Comment: Until sufficient data becomes available to support a
rational conclusion concerning the effects of NOX and
S02 controls on partlculate emissions, EPA does not
have an adequate basis for establishing a standard for
particulate emissions to be measured after FGD systems.
13. D-631
Comment; The partlculate emissions test data as well aa the cost
estimates which have been used to support the proposed
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revision are seriously outdated and thus fail to include a
great deal of recent information which demonstrates the
ability of particulate control systems on utility generat-
ing units to achieve significantly greater emission re-
ductions at reduced costs than those projected by EPA.
Specific examples of background document deficiencies are
cited,
14. F-lu
Comment: EPA's data base is too small and incomplete; it does not
include critical information on control-equipment design
and operating parameters, fuel characteristics, and oper-
ating characteristics of the generating unit.
* Overall cost effectiveness of proposed particulate NSPS
• Potential effects of proposed NSPS for NOX and S(>2 on
proposed particulate NSPS
• Data base on baghouses not representative of site and type of
generating units that will be subject to particulate NSPS
» Ability of test methods to measure accurately and precisely
the small mass of particulate matter necessary to determine
compliance.
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Averaging Time for Particulates
1. D-461
Comment: 24-hour, average not justified by EPA on technical or
economic basis.
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Particulate Control in the Presence of S02 and/or NOX
1. D-168, D-219, D-325, D-491
Comment: Control technology for participates has not been
adequately demonstrated in light of possible interactions
and synergistic effects from S02, NOX and/or scrubbing
chemicals. Reasons cited were:
» particulate carry over from scrubber
* difficulty of locating bmghouse of ESP downstream of scrubber
» dewpoint and corrosion problems with multiple systems
* advantages of using calcium oxide in place of limestone in
western units
• added energy required to compensate for mixed systems
* during load change and low load, excess air control is dif-
ficult and excess air (for NOX control) may cause high
partieulate emissions. NOX is difficult to control at low
load and low excess air due to flame instability.
2. D-627
Comment: Scrubbers probably cannot be used for removal of both
particulate and SC^. Scrubbers often generate
particulates and complete removal of this carry-over is
not possible in a reasonable scale.
3. D-631
Comment: UARG has not adequately demonstrated that acid mist is an
insurmountable problem. Technology to control this
problem probably exists or should be expected within a
reasonable time.
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Opacity Standard for Particulates
1. D-256
Comment; The proposed 10 percent standard for opacity is not based
on proven technology. Current 20 percent standard should
be retained,
2. D-369
Comment; Under typical operating conditions, natural deterioration
of ESPs would make achievement of 20 percent opacity
questionable.
3. 0-277
Comment: Opacity values should be correlated with particulate emis-
sion values during on-site testing.
4. D-256
Comment; Sections 60.42a(b) and 60.49a(e), should be changed to en-
sure that overlapping six minute periods are not con-
sidered an opacity violation. Also, allowances should be
made for emissions instability during rapid load changes.
5. D-231
Comment: The standard should reiterate that states have the right
to set more stringent opacity standards under 40 CFR
50.2(d).
6. D-455
Comment: EPA has not adequately addressed the matter of sulfuric
acid (112804) mist emissions from scrubbers on boilers
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firing high sulfur coal* It is my understanding that EPA
has taken data on such units and that the levels of
12804 are rather high. It seems obvious that such a
unit will have a plume: of l^SO^ mist and that there
would be difficulty in complying with the opacity re-
gulation. To fully evaluate the environmental impact of
scrubbers, the increased J^SQ^ emissions caused by the
burning of high sulfur coal should be evaluated with re-
spect to the reduction in SC>2 emissions with scrubbers.
7. D-486
Comment: The allowed opacity excursion to 27 percent gives the
impression of accuracy that does not exist.
8. D-631
Comment: It makes no sense to propose a standard which is one-third
of the current emission limit and fail to revise the op-
acity standard at the same time. The use of 20 percent op-
acity as an enforcement device is virtually useless. The
standard should be 5 percent or lower•
9. F-2 - -
Comment: Wet scrubbers (which will be required for S02 control)
should be exempt from the opacity standard because the
addition of limestone to the circulating fluid renders
them vulnerable to particuiate re-entrainment and thus
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possible violations. The 20 percent limit has not been
met by four of the company's five wet scrubbers.
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2.4.2-6G.43a Standard for Sulfur Dioxide
Sulfur Dioxide Emission Limit
1. D-82, D-87, D-90, D-145, D-147, D-156, D-167, D-194, D-2I5,
D-216., D-218, D-219, D-223, D-224, D-225, D-227, D-231, D-232, D-234,
D-238, D-242, D-244, D-250, D-251, D-254, D-256, D-257, D-261, D-263,
B-265, D-266, D-270, D-272, D-274, D-276, D-277, D-288, D-289, D-294,
D-300, D-3Q4, D-305, D-306, B-307, D-308, D-309, D-310, D-311, D-312,
D-315, B-317, D-319, D-320, D-321, D-322, D-325, D-329, D-330, D-332,
D-333, D-334, D-335, D-336, D-337, D-339, D-340, D-345, D-357, D-361,
D-366, D-367, D-368, D-370, D-371, D-373, D-38Q, D-397, D-398, D-403,
D-404, D-405, D-409, D-410, D-414, D-415, D-417, D-418, D-421, D-423,
D-425, D-426, D-427, D-429, D-433, D-435, D-437, D-438, D-440, D-442,
D-445, D-446, D-447, D-448, D-449, D-450, D-451, D-452, D-457, D-458,
D-459, D-460, D-461, D-463, D-464, D-467, D-468, D-469, D-471, D-473,
D-475, D-476, D-477, D-478, D-481, D-482» D-483, D-488, D-489, D-490,
D-491, D-498, D-508, D-514, D-516S D-519, D-523, D-531, D-537, D-538,.
D-540, D-541, D-542, D-545, D-547, D-548, D-549, D-552, D-556, D-558,
D-561, D-571, D-590, D-610, D-612, D-613, D-614, D-616, D-620, D-621,
D-628, D-635, D-639, D-642, D-643, D-648, D-651, D-657, D-678, D-683,
D-684, D-694, F-lb, F-ld, I-ls, F-lu, F-lw, F-lx, F-ly, H-10, H-13
Comment: EPA should adopt the partial scrubbing (sliding scale)
proposals of DOE, UARG, or similar plan. These responses
had various reasons for proposing the sliding scale such as
western vs. eastern coal, technology, less sludge,
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cost/benefit, etc., but all are characterized by explicit
support of a sliding scale.
2. D-l, D-2, D-7, D-72, D-102, D-115, D-132, D-237, D-239, D-247,
D-286, D-382, D-399, D-40Q, D-521, D-539, D-579, D-627, D-673, D-733,
F-le, F-ig, F-lu, F-lx, F-2
Comment: EPA should not promulgate a full scrubbing regulation*
Such a regulation is inflation-causing, not necessary to
protect air quality, too restrictive, etc. None of these
comments offered an alternative standard.
3. D-27, D-28, D-32, D-41, D-52, D-67, D-l14, D-284, D-407, D-466,
D-583, F-lq
Comment: Full scrubbing discriminates against western coal. No
explicit alternative is proposed.
4. D-157, D-175 (1,2 lb/106 Btu), D-212, D-747 (0.4 lb/106 Btu),
D-232 (0.9 lb/106 Btu}, D-262 (0.5 lb/106 Btu), D-271, D-401 (0.8
lb/106 Btu), D-697 (0.2 lb/106 Btu), F-li
Comment: A less stringent emission limit should be adopted, (Values
suggested are shown in parentheses.)
5. D-33, D-70, D-74, D-76, D-95, D-103, D-l07, D-110, D-130, D-131,
D-157, D-169, D-172, D-l74, D-194, D-195, D-202, D-211, D-229, D-23Q,
D-243, D-245, D-246, D-282, D-285, D-327, D-342, D-350, D-351, D-352,
D-355, D-359, D-363, D-364, D-372, D-392, D-413, D-416, D-444, D-480,
D-505, D-510, D-518, D-522, D-567, D-568, D-624, D-626, D-697, D-721,
D-723, D-729, D-730, F-lc, F-li, F-ln, F-lt, F-lo, H-8
2-117
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Comment: The standard as proposed should be adopted on the basis of
health effects, reducing PSD increments, intent of
Congress, etc.
6. D-443 D-46, D-48, D-49, D-57, D-60, D-61, D-69, D-71, D-75, D-77,
D-86, D-91, D-92, D-93, D-126, D-128, D-133, D-135, D-139, D-141,
D-1963 D-207, D-323, D-462, D-569, D-688, F-ln
Comment: The standard as proposed should be adopted but old plants
should also be included in NSPS
7, D-6, D-85 D-9, D-10, D-63, D-78a, D-78b, D-793 D-83, D-84, D-85,
D-923 D-94, D-97, D-98, D-99, D-101, D-1D4, D-105, D-106, D-107,
D-108, D-112, D-116, D-117, D-118, D-119, D-12L, D-123, D-125, D-129,
D-130, D-136, 0-137, D-140, D-142, D-I43, D-144, D-146, D-148, D-149,
D-151, D-154, D-155, D-157, D-161, D-162, D-166} D-170, D-172, D-173,
D-174, D-176, D-177, D-178, D-180, D-182, D-183, D-184, D-I85, D-186,
D-187, D-188, D-190, D-192, D-194, D-197, D-198, D-199, D-200, D-201,
D-202, D-2083 D-209, D-213, D-220, D-221, D-226, D-229, D-235, D-236,
D-240, D-243, D-249, D-264, D-268, D-273, D-275, D-278, D-280, D-293,
D-313, D-3243 D-327, D-331, D-350, D-351, D-352, D-353, D-354, D-355,
D-358, D-3593 D-360, D-362, D-363, D-365, D-372, D-374, D-375, D-377,
D-378, D-379, D-381, D-384, D-385, D-386, D-387, D-388, D-389, D-390,
D-391, D-393, D-394, D-395, D-396, D-4063 D-411, D-428, D-434, D-441,
D-456, D-492, D-493, D-494, D-495, D-4963 D-497, D-499, D-500a D-501,
D-502, D-503, D-504, D-506, D-507, D-513, D-517, D-524, D-525, D-551,
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D-564, D-565, D-566, D-569, B-570, D-576, D-577, D-601, D-623, D-631,
D-645, D-646, D-659, D-663, D-666, D-675, D-688, D-691, D-703, D-704,
D-705, D-706, D-708, D-709, D-710, D-711, D-712, D-713, D-714, D-715,
D-717, D-718, D-719, D-720, D-722, D-724, D-728, D-738, D-749, D-750,
F-li, F-ln, F-lt, H-ll
Comment: A more stringent emission level should be adopted. The
Japanese experience supports this. Removal efficiencies of
90 percent and 93 percent can be achieved and are
suggested. The intent of Congress and PSD increment
reductions support this approach!
8. D-72, D-335
Comment; Utilities with current low-sulfur coal contracts should be
exempt for the life of the contract.
9. D-443, D-475
Comment: The proposed SC>2 removal requirement should be limited to
coal-fired units only because;
• few, if any, non-coal fired units will be built
• they can be evaluated on a case-by-case basis under PSD
« very little effort was made to justify the new standard for
liquid and gaseous fuels.
10. D-467
Comment: Section 60.43a(b) states that even during the three days
per month in which the 85 percent reduction is not re-
quired, S(>2 must be reduced by 75 percent "at all times".
The term "at all times" requires clarification since it is
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somewhat in conflict with the 24-hour averaging concept.
It is recommended that this subsection be rewritten to
clearly indicate that the 75 percent removal is to be
averaged over at least a 24-hour period.
11. D-468
Comment: The standard should be rewritten to measure allowable
emissions in terms of mass of SC>2 per megawatt hours of
output. This will create an incentive for increased
combustion efficiency.
12. D-4S8
Comment: It is recommended that EPA provide a variance for mine-run
fuel to allow reporting of percent removal on a monthly
average and compliance determined on a basis of emission of
1.2 lb/106 Btu or lower.
13. D-175, D-644
Comment; The standard should not dictate method for achieving low
emissions. This amounts to a control of the marketplace
and discriminates against low sulfur coal. The standard
should give freedom of choice on how to comply.
14. D-631
Comment: The law and its legislative history require EPA to set a
uniform nationwide percentage reduction. Promulgation of
any "sliding scale" would be illegal, whether done directly
or through EPA's authority to subcategorize.
•2-120
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15. D-491
Comment: In view of the limited experience with reliable FGD con-
trol on high sulfur coal, the emission limitation in the
NSPS should not be lowered below 1.2 Ibs/MBtu for this type
of coal.
16. D-491.
Comment: All of the economic modeling performed to date by IGF and
NERA show that none of the proposed alternatives will
reduce S02 emissions substantially more than others.
This increases the importance of cost, environmental and
energy impacts in the standard development. The UARG
sliding scale is less costly, uses less oil, and produces
less sludge. Therefore, it should be adopted.
17. D-631
Comment: The 3-day-per-month exemption for percent reduction should
not be allowed since scrubbers are reliable and do not need
exemptions. ...
18. D-631
Comment: • Establishing an emission floor for S02 is clearly illegal
since it is the same as a sliding scale.
19. D-554
Comment: Western bituminous coal should not be exempt because of
severe economic impacts created on the Appalachian bitumi-
nous coal region.
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20. D-536
Comment: The S0£ standards proposed by EPA, DOE or UARG should not
be adopted. All of these are too costly. No alternate
given.
21. D-551
Continent: Since the sulfur and other mineral content of coals vary
from one region to the next, standards of emissions should
be set in parts/million, rather than as a percentage of
sulfur to be removed.
22. F-ls
Comment: The argument that maximum S02 control would support local
economies through use of local coal is invalid and cannot
be supported as cost effective. Arguments of the Sierra
Club and Red Mesa Chapters of the Navajo National lawsuit
calling for maximum control of S02 regardless of sulfur
content of coal are based upon the premise that there
should be regulation simply for regulation's sake and do
not reflect the cost/benefit approach mandated in the 1977
Clean Air Act amendments. Requirements differ throughout
the nation and a uniform standard is neither logical nor
efficient.
23. D-751, D-753, D-755, D-756
Comment: An emission limit of < 1.2 Ib SC^/IO^ Btu (as low as
0»55) with 90% removal will preclude the use of: 57% of
Iowa coal, 74% of Illinois coal, 891 of Indiana coal, 100%
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of Western Kentucky coal, 100% of Ohio coal, and 861 of
Northern West Virginia coal. (Data is submitted with
D-756.)
24. H-17
Comment: The Department of Energy recommends a flexible approach to
S(>2 ceilings/floors and percent reduction, giving
industry the option of complying with daily or monthly
standards.
25. H-19
Comment; Since new power plants will be built, there will be an
increase in emissions, regardless of the controls used.
The Department of Agriculture favors a NSPS that will
employ the maximum use of full emissions control while
fairly considering the effects on economics, energy, and
the benefits to the environment while minimizing the
present atmospheric loading of sulfates.
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Best System of Emission Reduction for Sulfur Dioxide
1. D-120, D-152, D-343
Comment: Technology exists to remove >9Q percent of sulfur dioxide
and should be considered.
2. D-157, D-176, D-178, D-350, D-355, D-357, D-626, D-631, D-633,
F-Lc
Comment: Technology exists to remove greater than 90 percent of
sulfur dioxide as demonstrated by the Japanese experience.
3. D-145, D-175, D-210, D-233, D-467, D-735
Comment: Equipment to meet the S02 standard is not available
» limited experience
* capital, operating, and maintenance costs
* high risk equipment
4. D-168, D-216, D-244
Comment: Gross overdesign is required on large units; current effi-
ciencies are based on small units.
5. D-252
Comment: The availability of scrubbers was not assessed sufficient-
ly.
6. D-231
Comment; Regarding FGD availability; object to EPA being able to
specify what "minimal amount of spinning reserve" must be
maintained.
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7. D-2473 D-330, F-ls, F-2
Comment: Concerned about de facto elimination of dry scrubbing.
• 10 percent lower cost
* 10 percent lower total plant water requirements
• sludge handling simplified
8. D-246
Comment: New units have solved problems of corrosion, plugging, e
9. B-347
Comment: Cold.end corrosion and scaling maintenance problems.
10. D-325
Comment: Interactions between controls have not been demonstrated.
11. D-14, D-30
Comment: Support coal cleaning.
12. D-418, D-491} D-519
Comment: The Japanese experience does not support the standard be
cause of the following possible differences:
» the degree of closed loop versus open loop operation
* the impact of trace contaminants in oil and coal on closed
loop operation
* the impact of different inlet SC>2 concentrations
• S02 uptake per volume of absorbent liquid
* the extent to which Japanese oxidize to gypsum and thus
provide seed crystals for recycle to control scaling and
produce a saleable end product instead of sludge
• the extent to which Japanese are able to perform routine
maintenance during nighttime low load operations
2-125
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* the impact of the Japanese continuous coal blending on the
efficiency data
* only 5 FGD operate on coal-fired plants (coal has chloride
buildup problem which has scaling and corrosion effects)
* Japanese have much higher blowdown than allowable in U.S.
(e.g. more open loop)
• market for gypsum reduces waste disposal problems
* no data in record comparing technology, economics, or costs
for Japanese systems
13. D-442
Comment: There has been no successful application of an FGD system
on Illinois coal which is very high in chloride content,
creating additional problems in scrubbing.
14. D-464
Comment: Based on one year of operating experience with FGD, it is
concluded that the technology required to meet the standard
has not been adequately demonstrated on Indiana-Illinois
Basin high sulfur coal.
15. D-218
Comment; Scrubbers have a poor record on coals mined in the southern
part of the middle Atlantic region.
16. H-12
Comment: Provides additional analyses of the proposed standard
alternatives. Conclusions point out the following:
* sliding scales produce 3-4% greater emissions at cost savings
of up to $800 million in 1990 and $1.5 billion in 1995
2-126
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• low ceiling options are more cost effective than high ceiling
cases
» sharp increase in incremental costs of SC>2 removal in going
from sliding scale to full control
« EPA has not analyzed exposure and health effects
• utility oil consumption is higher under full control than
sliding scales
• distribution of coal production and price is insensitive to
the choice of performance standard
17. H-14
Comment: Preliminary results of a study of the economics of phased
installation of FGD systems indicate overall savings on
the order of 0.7 to 1 mills/kwh, compared .to a single-step
strategy. The phased strategy examined called for
proceeding through four stages to scrub additional amounts
of flue gas in 25 percent increments from year 0 to year
15. Eighty-five percent of the S02 would be removed
from the flue gas by a scrubber with 90 percent design
• capability at an energy penalty of 1.6 percent of gross
boiler output. Cost estimates are reported in 1978
dollars after escalation to 1983.
18. D-630
Comment: Coal blending can reduce but not eliminate sulfur
variability.
19. D-632
Comment: Coal blending to meet a standard under a sliding scale
?
would cost $0.94/toa at the Pawnee Power Station in
2-127
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Colorado - less than 1/7 the cost ($6»92/ton) to install a
wet scrubber.
20. D-519
CommentJ Equipment guarantees quoted by EPA do not state averaging
time.
21. D-519
Comment: Sodium carbonate scrubbing, dual alkali scrubbing, mag-
nesium oxide scrubbing, Wellman-Lord, and spray
dryer/fabric filter technologies are not demonstrated or
not universally applicable due to unique cost and/or
unique process considerations.
22. H-13
Comment: Use of injection of additives such as adipic acid in the
scrubber slurry as presented in the December 8, 1978,
Federal Register is not seen as meeting the definition of
best technological system which has been adequately
demonstrated. No test conditions or operating experience
with this control technique are discussed. Therefore, it
should not be further considered by EPA until It has been
adequately demonstrated.
23. D-519
Comments Stack liner problems:
* takes issue with findings that liner problems can be solved
by using more expensive materials — Agency doesn't have
evidence to support this or statements of manufacturer
guarantees. Cites numerous cases of corrosion.
2-128
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24. D-491
Comment: Long-term reliability of closed-loop scrubber operation has
not been demonstrated.
25. D-491
Comment: SC>2 control technology has not been adequately demonstra-
ted for the following cases:
* continuous long-term operation on low sulfur coal with an
open-loop control system
• continuous long-term operation on low sulfur coal with a
closed-loop control system
• continuous long-term operation on high sulfur coal with a
closed-loop control system
26. D-491
Comment: Proposed S02 standard was based on the most advanced
technological system of control. This forecloses the de-
velopment of competing scrubber and "front—end" tech-
nologies which are less advanced but have the potential for
a better balance among costs, environmental and energy
benefits.
27. D-631
Comment; The operational differences between Japanese and American
scrubbers which result in the high efficiency and reliabil-
ity of Japanese scrubbers include:
* attitude of plant operators
* skill of FGD system operators
* close government surveillance of power-plant emissions
* specific technical differences in the mode of scrubber
operation.
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Since all of the above, are transferable to U.S. facilities,
there is no reason why average efficiencies of 94% cannot
be achieved.
28. D-519
Comment: Use of Mg4* to reduce scaling is not a proven technique.
The examples used by EPA are inappropriate.
29. D-609
Comment: The adoption by EPA of NSPS less stringent than those which
-one of the nation's largest utilities has agreed can be met
would be nothing short of irresponsible. (Enclosed a.
Stipulation re BACT from Pacific Gas and Electric Company
for proposed fossil 1 and 2 power plant which defines BACT
as:
• S02 - 95 percent removal, 24 hour average
* PM - 0.003 gr/scf
* NOX - 0.45 Ib/mmBtu (possibly as low as 0.034 Ib/mmBcu)
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Adequacy of the Sulfur Dioxide Data Base
1, D-369
Comment: -The following comments on the S02 'data base are submit-
ted:
* Bruce Mansfield No. •! results Have Been misused; plant was
operating at 50% load
# La Cygne "excellent" availability subject to pending repairs
which have not been considered
• Question overall availability data
* Bruce Mansfield base loaded - new facilities will be dis-
patched to accomodate load
a) FGD reagent slurries will go off optimum pH under
new load
b) see real problems with measurement and monitoring
removal capability
2. D-371, D-373, B-449, D-575, D-610
Comment: Modeling does not adequately support the standard
* Large discrepancy between EPA and NERA
• NERA study shows Texas will pay 25% of national cost of full
scrubbing
« • In the detailed "further analysis" (Dec. 8, L978, FR) report
of the consultant we noted a critical error in the assumption
used relative to sulfur content of Powder River coal. Using
an assumption of 1 Ib sulfur/million Btu's*overstates Che
sulfur content by about 100 percent; and consequently, the
removal costs would be vastly overstated as well.
* Submission of RT1 report (D-610) showing reasons for dis-
crepancies between IGF and NERA models. Favors ICF model but
a NSPS of "0.55" or "full West/0.55 rest" as more favorable
(cost/benefit) than either EPA, DOE or UARG.
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3. D-397
Comment; Data does not justify 85% removal of sulfur dioxide.
4. D-397
Comment: Should not use data from demonstration units, nor spot or
performance tests.
5. D-448
Comment: Should not justify standard on eastern versus western coal
economic issues.
6. D-435
Comment: The economic impact of the proposed regulations is incom-
plete.
• independent assessment of impacts by modeling
* critical of linear programming approach—washes out geo-
graphic detail influencing individual power plant fuel
options
* analyses* of 4 sites on coal transportation
Indianapolis Louisville Austin Tampa
(1) daily avg. 3 7600/176/-- 7600/165/— 3800/74/— 7600/189/™
.2 Ib floor
EPA
(2) daily avg., 3800/24/229 3800/24/46 3200/36/106 3800/24/236
.5 Ib floor,
fix bypass
(3) daily avg. , 6400/17/274 6400/17/91 6400/29/145 6400/17/282
.5 Ib floor,
variable
bypass
(4) monthly avg., 7000/16/366 7000/16/175 7000/27/221 7000/16/366
.54 Ib floor,
variable
bypass 3 DOE
2-132
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(5) monthly avg., 8900/10/641 8900/10/450 9600/20/473 8900/10/641
sliding scale,
variable
bypass, UARG
Legend for table: emissions/sludge/cost saving $(10")
(tons) (10^ tons) over EPA (30 yrs,
• - 500 MM, 8942 Btu/
kWh)
7. D-450 ' '
Comment: Full scrubbing too costly with respect to benefits.
• cites NAS report indicating benefits of $200/ton S02
removed; coats of $l,184/ton S02 removed shows a large
imbalance.
8. D-455 ' ' •
Comment: It is improper to evaluate the cost of the standard on the
basis of gross cost or average cost per consumer. A more
'i
meaningful way would be to compare the incremental increase
in the consumer cost with the incremental decrease in emis-
sions. If emissions are not decreased by the effect of the
regulations or are only decreased a 'small amount relative
to the cost, then money is being wasted.
9. D-455
Comment: The continuous monitoring data from the Cane Run and Bruce
Mansfield Power Plants which were used to determine scrub-
ber removal capability is totally deficient.
10. D-458, D-491
^
Comment: EPA does not show that the present limited experience with
non-lime/limes tone technology can be used to justify the
2-133
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higher level of removal efficiency and availability re-
flected in the standard on a continuous basis.
Extrapolation from test units to commercial scale is
difficult.
11. D-461
Comment; The costs specified on page 43FR42163 are distorted. EPA
states $260 to $1600/ton for low sulfur coal while industry
estimates $900 to $2000/ton.
12, D-467
Comments Experience has shown an 8-10% inflation rate for new facil-
ities, not the EPA 5.5%.
13. D-459
Comment: The project to determine the percent S02 reduction data
for the four FGD systems listed in Section 4.2.4 of the
background supplement EPA-4SO/2-78~007a-l was not of sound
scientific design. This project proports to evaluate the
probability distribution of FGD 24-hour average S02
removal efficiencies. It appears that fatal errors
were made in the design and execution of this project.
Specifically, there was the lack of uniformity in the sam-
pling period, in continuous monitoring equipment, and in
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the sample points. Also, the results were biased by ex-
clusion of some sampling data and the apparent selection of
an extremely small number of FGD systems.
14. D-479
Comment: Control costs will depend on variables which are not known:
1) cost of coal transportation
2) labor increases
3) strip mine regulations
4) sulfur content and Btu value of different coals
5) capital cost estimates for control equipment
6) power plant capacity factor used
7) heat to power (Btu to MW) conversion efficiency value used
8) annualized control equipment cost:
* depreciation
* insurance
* taxes
* interest
• operating and maintenance costs
9) growth estimates too low
15. D-483
Comment: Data base does not warrant optimistic assessment of levels
of reliability and removal efficiencies of FGD.
16. D-485
Comment: Data base does not appear to correctly calculate cost of
full scrubbing to the. consumer.
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17. D-485, D-682
Comment: Data base does not appear to substantiate the claim that
proposed regulations will substantially reduce S02 emis-
sions.
18. D-488
Comment: The EPA economic analysis assumes coal costs increase at
6.51 per year. Our system estimates 10 to 15%.
19. D-491
Comment: There are no EPA data which support the assumption that
scrubbers are demonstrated at or near 90 percent relia-
bility with one spare module.
20. D-491
Comment: The data base used for assessment of the lime/lime stone
FGD technology does not establish that such systems
can attain the required levels of efficiency on a con-
tinuous basis.
21. D-491
Comment: No where do EPA's contractors relate the removal ef-
ficiencies cited for S02 to averaging times. In ad—
ditionj no evidence is presented that high removal ef-
ficiencies can be achieved on a continuing basis without
substantial and unproven changes to present FGD systems,
22. D-519
Comment: The following comments are submitted with respect to
lime/limestone capability:
2-136
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In general EPA Ignores Bechtel findings that an 85 percent
standard will require further work with respect to .chemistry,
need for spare modules, etc.
Green River has had poor availability contrary to EPA record
Mojave scrubber is no longer working
Four Corners no longer operating to control SC>2
Mojave, Cholla, and Four Corners all operated with 200 ppm
input
* Cane Run. #4 and Paddy's run use scarce carbide lime— atypical
and costly
• St. Clair operated at unacceptably high excess air for con-
tinual operations.
* Bechtel stated that Shawnee results were under atypical oper-
ating conditions
* Phillips and Green Elver were never evaluated under
continuous conditions.
23. D-512
Comment: Record substantiates the claim that the proposed regulation
will have -no major impact on emissions in 1990.
24.- D-582
Comment: Power plant cost data are submitted with two comments. The
coiamenter favors the" sliding scale option.
» question the cost analyses that do not include the cost of
replacing a scrubber after 20 years on a power plant with a
30 year plus life. (ICF material pg. 10, Dec. 12, 1978 hear-
ing material)
* question the values used for "scrubber capital charge rate"
in the same analyses. Assuming this is equivalent to "fixed
charge rate", we would expect the value to be fetween 15—20
percent for investor owned utilities, and somewhat less for
public utilities.
2-137
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25. D-631
Comment; The result of EPA1s modeling is only as good as the input
data and model assumptions. Therefore the model results
are totally inadequate since,
• the conclusions are largely determined by a single issue -
the price of oil
• secondary effects on environment, energy and costs are
neglected
• EPA's incorrect interpretation of the meaning of the phrase
"taking into consideration costs",
* failure to recognize the sensitivity of small changes in
input data to the overall results
26, D-611
Comment: The data which were obtained during the EPA continuous mon-
itoring studies do not accurately characterize FGD perform-
ance variability due to the problems which were encountered
during the studies and the resulting errors in the mon-
itoring data. In addition3 the 24-hour average efficiency
data which EPA obtained during the monitoring studies can-
not be assumed to be representative of long-term, steady-
state FGD performance because:
• many of the systems produced only sporadic, short-term data
* one system was monitored during initial startup
* insufficient data were obtained during four of the five
studies., which were included in EPA's statistical analyais3
to characterize long-term FGD performance variability
2-138
-------
• during the FGD monitoring study program, neither a diluent
monitor accuracy test nor a combined system accuracy perform-
ance test was reported at any of the continuous monitoring
sites
27. D-744, D-756
Comment: Inadequacies in the data base regarding the relationship of
short-term and long-term scrubbing and the cost or
feasibility of coal washing precludes consideration of a
lower ceiling or higher removal efficiency requirement than
proposed,
28. D-755
Comment: Apparently no assessment of the employment ippacts of the
proposed S(>2 standard has been made. Also, the
environmental benefits"have yet to be revealed on any basis
other than aggregate national and regional emission
quantities.
2-139
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Averaging Time for Sulfur Dioxide
1. D-98, D-157, D-169, D-174, D-245, D-331, D-341, D-350, D-351,
B-354, D-355, D-363, 0-375, D-381, D-386, D-3S8, D-393, D-394, D-406,
D-411, D-494, D-496, D-499, D-500, D-5Q4, D-506, D-513, D-517, D-564,
B-569, D-601, D-623, D-624, D-631, D-645, D-646, D-697, F-li
Conment: Favors 24 hour averaging time
• 30 day average permits gross violations over short time
periods
• averaging time will affect SIP plans for smelters which
are based on short term averages
* easier enforcement
* no reason given
2. D-145, D-147, D-156, D-167, D-215, D-216, D-218, D-219, D-223,
D-225, D-231, D-232, D-238, D-244, D-247, D-250, D-256, D-259, D-314,
D-315, D-317, D-322, D-370, D-371, D-403, D-404, D-405, D-407, D-410,
D-415, D-417, D-418, D-425, D-438, D-442, D-444, D-446, D-447, D-448,
D-449, D-459, D-461, D-464, D-467, D-476, D-483, D-488, D-490, D-491,
D-514, D-523, D-S71, D-610, D-620, D-630, D-642, F-lq, F-ly, F-laa,
H-10, H-13
Comment: Favors 30 day averaging time
• coal variability
» reliability of continuous monitoring
» lack of data showing that 85% reduction on 24 hour
average basis over extended periods is achievable
• irregularities of operation (load changes, etc.)
2-140
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* reliability of scrubbers
• lime variability
3. D-440
Comment: Fuel treatment is baaed on 90-day averaging; therefore,
S02 removal should be based on 90-day average.
4. D-482
Comment: Favors 3-hour averaging time to make the standard the same
as PSD and NAAQS.
5. D-455
Comment: The SC-2 standard, as written, is unwieldy in regard to
the calculations to determine 24-hour removal by the scrub-
ber. It is ridiculous to have a 24-hour standard calcu-
lated against a quarterly fuel-cleaning credit with 3 days
per month exemption. It would seem more reasonable to
apply ail standards and credits to a 30-day period with
indication of compliance using analyzers and compliance
testing using Method 6.
6. D-491
Comment: The data on which EPA bases its averaging time conclusions
are not valid because the short term performance test data
are not analyzed in a manner to permit such conclusions,
Certification procedures were not always followed and
portions of the data were excluded as a result of system
failures.
2-141
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7. D-744
Comment: Question the conclusion made regarding the relationship
between short-term scrubber performance (24-hour average)
and long-term scrubber performance (30-day average).
8. H-17
Comment: The Department of Energy reconanencls a flexible approach to
S02 ceilings/floors and percent reduction, giving
industry the option of complying with daily or monthly
standards.
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Sulfur Removal Credit
1. D-369
Comment; Does 862 removal start with crude oil at the well head or
refined oil?
2. D-230
Comment: Concern is expressed over the failure to allow sulfur .
credits for "cleaning" and/or refining high sulfur crude
oil,
3. D-321
Comment: No credit given to 10% to 40% sulfur in flyash from low
sulfur western coal (depending on sodium in ash).
4. D-223
Comment: Supports credits for pulverizing^ bottom ash and flyash.
5. D-259
Comment: Proposed standard does not say how credits for precleaning
will be incorporated into continuous monitoring data.
6. D-490, D-485
Comment: Supports sulfur credits
7. D-467
Comment: The preamble states that rotary breakers or coarse screens
will not be considered a fuel pretreatment. However3 the
House Report states that all processing steps performed on
a material from its natural state should be taken into
consideration.
2-143
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8. D-488
Comment: The method for calculating percent removal by coal cleaning
or ash interaction by using coal sampling prior to
combustion will require approximately a 200 pound sample
per hour per generating unit. This will require a very
elaborate, expensive sampling system,
9. D-217
Comment; A mechanism should be provided to apply the refinery de-
sulfurization credits to petroleum coke sold to utilities
for fuel and to fuels from alternate energy sources such as
tar sands or oil shale.
10. D-217
Comment: Although fuel oil pretreatment to remove sulfur can be
credited toward the 85% reduction, the respondent desires
that the process of fuel oil desulfurization at a refinery
be specifically mentioned as an accepted method of fuel oil
pretreatment.
11. D-217
Comment: The proposed formula for calculating S02 removal ef-
ficiency by fuel oil pretreatment "breaks down" in a number
of common refinery situations, e.g>, when fractionation,
cracking or coking processes intervene between de-
suifuriaation and fuel oil blending. (An alternate formula
is proposed.)
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12. D-608
Comment; There should be a decision by the U.S. EPA relating to the
emission factor to be used for S02 emissions when burning
Western subbiturainous coal from Cols trip County in Montana.
13. D-523
Comment: Credit is to be given for sulfur removal prior to coal use,
yet the scale of credit appears inequitable; for instance,
if 25 percent of the sulfur is removed by pretreatment3 the
control requirement for S02 is reduced by oaly 5 percent
(43FR42173). There should be a more direct trade-off be-
tween sulfur removal in pretreatment and the present re-
duction requirement,
14. D-631
Comment: Supports sulfur credits for washing due to numerous side
benefits,
* reduces coal variability
• reduces coal shipping costs
* reduces boiler and scrubber maintenance
0 reduces sludge handling
2-145
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2.4.3-60.44a Standard for Nitrogen Oxides
Nitrogen Oxides Emission Limit
1. D-132, D-145, D-156, D-167, D-168, D-2Q5, D-216, D-218, D-219,
D-223, D-224, D-231, D-232, D-234, D-238, D-250, D-263, D-271, D-287,
D-300, D-301, D-315, D-320, D-322, D-325, D-330, D-347, D-369, D-370,
D-380, B-397, D-401, D-410, D-417, D-421, D-425, D-426, D-433, D-438,
D-446, D-447, D-448, D-449, D-451, D-458, D-460, D-461, D-464, D-467,
D-471, D-473, D-475, D-476, D-477, D-481, D-483, D-489, D-491, D-519,
D-611, D-642, F-lb, F-lg» F-ls, F-lu, I-lw, F-lx, F-ly.
Comment: The majority of the commentors were critical of the
proposed Units on grounds of insufficient control tech-
nology demonstration (see next subsection)* Additional,
though less frequently mentioned, comments included insuf-
ficient health effects justification, retraining for new
technology, and the discrimination against the use of sub-
bituminous coal due to its stricter standard* All of the
above comments either explicitly recommended no change to
the current standard or made a strong criticism of the
proposed standard.
2. D-238, D-370
Comment: These comments suggested a 0.6 lb/10^ Btu Standard based
on the inability of technology to achieve the proposed
standard. In both cases, no specific fuel type was
mentioned nor was an applicable technology mentioned. The
2-146
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comtnentors stated that a 0.5 lb/10^ Btu standard had not
been demonstrated on a continuous bas-is,
3. D-9, D-170, D-229, D-268, D-313, D-462, D-505, D-631, H-8
Comment: Either agreed with proposed standard or suggested more
stringent standard as follows:
D-9 (0,1 ppm/hr)
D-170 (Stricter Controls)
D-229, D-462, D-505 (Agree with Standard)
D-268 (0.38 - 0.45 lb/106 Btu)
D-313 (0.018 lb/106 Btu>
D-631 (0.45 lb/106 Btu with requirement for facilities to
aceomodate the use of catalytic anmonia injection when
that control technique is fully developed, e.g.,
potential of .02-.05 lb/106 Btu)
Most of these coimnentors felt that the record indicates a
strietei* standard is schievable. It was pointed out by
several commentors that vendor guarantees to the California
Air Resources Board indicate that a 0.45 Ib/lO^ Btu is
readily achievable. In addition, emissions of 0.34
lb/10^ Btu in Japan by a U.S. vendor are reported
as well as pilot results with ammonia injection.
4. D-366
Comment: NOX standard should only apply to station complexes with
a total of 4000 x 106 Btu/hr or greater.
2-147
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5. D-438, D-448
Comment: Validity of formula for coal mixing not proven and not
practical to implement.
6. D-468
Comment: Standard should be rewritten to measure allowable emis-
sions in terms of mass of NOX per megawatt hours of
output. This will create an incentive for increased
combustion efficiency.
7. D-488
Comment: Texas lignite should also be included in 0.8 Ib/lQ^ Btu
requirement when burned in a slag tap furnace.
8. D-203
Comment: The equation at 43 FR 42176 should read:
PSNO = (w<86) + x(130) + y(21Q) + zC26Q»/(w+x+y+z).
2-148
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Best System of Emission Reduction for Nitrogen Oxides
1. D-145, D-L53, B-168, D-205, D-219, D-224, D-232, D-234, D-238,
D-263, D-271, D-300, D-301, D-315, D-322, D-370, D-404, D-409, D-418,
D-426, D-442, D-455, D-461, D-463, D-491, D-519, B-611, D-642, F-lw
Comment; These comments explicitly reflected a feeling that there
has "been insufficient demonstration of the.control tech-
nology (combustion modification). The principal concerns
expressed were with respect to increases in boiler tube
corrosion under low NOX" operation and increased slagging.
The appropriateness of coupon testing was questioned and
the fact that long term corrosion data are still being col-
lected was cited as evidence of insufficient demonstration.
Increased slagging due to a reducing atmosphere
characteristic of staged combustion was the primary slag-
ging concern. In addition, the regulation would not allow
sufficient flexibility to Increase excess air to reduce
slagging since this would tend to raise NOX levels.
2, D-132, D-156, D-167, B-168, D-218, D-250, D-287, D-320, D-322,
D-330, D-347, D-370, D-400, D-410, D-433, D-437, D-442, D-444, D-449,
D-451, D-491, D-519, D-611, F-lb, F-lg, F-lu, F-lx
Comment: These comments are with respect to the apparent monopoly
on design by 1 or 2 manufacturers.
* Three of four boiler manufacturers have recommended
that EPA not change the NOX NSPS
2-149
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* One boiler manufacturer meets standard due to its tan-
gential fired boiler design
• A second boiler manufacturer has not achieved a 0.45
lb/10° Btu guarantee for one unit after 2 years of
operation
* A third manufacturer has not brought low NOX unit
guaranteed to meet 0.45 lb/10^ Btu on-line yet
• Boiler manufacturer guarantee not on continuous basis
but on compliance test basis-big difference
* Justice Department has commented on implications for
competition
3. D-320
Comment: This comaentor claims San Juan facility could, at best,
operate at 0.6 lb/10^ Btu whereas it was designed to meet
a 0.45 lb/106 Btu standard.
4. D-223
Comment: Standard should be function of boiler type.
5. D-369, F-laa
Comment: Tables 6-2 and 6-9 of EPA 450/2- 78/005a show boiler tube
corrosion losses of 285-488 percent in certain test
coupons. These losses are significant but are discounted
by EPA.
6. D-271
Comment: Experience with tangential ly fired boiler with over fire air
burning sub-bituminous western coal resulted in excess
slagging after 3 days of operation. (No other specifics
are given as to operation.)
2-150
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7. D-325, D-491, D-519, D-611
Comment: Interaction with other controls such as FGD and NOX not
demonstrated.
8. D-3, D-491, D-519, D-611
Comment: Reheat for scrubbing will increase NOX emissions.
9. D-6G9, D-631
Comment: Additional control of NOX, far beyond what EPA is cur-
rently contemplating, can be achieved at a very reasonable
cost. As a minimum, California Air Resources Board has
guarantees from two vendors for 0,45 lb/10° Btu (no coal
type or averaging time specified). In addition GARB is
'specifying'that a capability to use ammonia catalytic in-
jection be incorporated in new plants. A Japanese coal-
fired power plant (Isogo Power Station) has demonstrated
removal efficiencies of 90 percent or NOX emissions of
0.034 lb/10" Btu using a pilot ammonia catalytic injec-
tion system (no coal type or averaging time specified).
Also, at least one Japanese boiler built by an American
manufacturer operates at 0.34 lb/10 ,Btu.
10. D-156, D-491, D-519
Comment: EPA did not consider unit efficiency reduction along with
boiler effects. Lower combustion temperatures with
low-NOx may reduce steam turbine inlet temperatures and
thus overall electrical efficiency.
2-151
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11. D-491, D-519
Comment: Question results of control technology improvements shown
in record:
• Agree with EPA that expanded boiler size reduces
NOX« However, points out that (1) beyond a limit,
steam temperature becomes depressed and unit loses
turbine efficiency and (2) units designed for current
NSPS already use this technique and little gain can be
expected in future units*
* Gains indicated by EPA from staged combustion were
demonstrated on older units. More modern units already
achieve some of the effects of staged combustion.
* Overfire air does not appear to be a long range control
due to concerns about potential adverse side effects
attributed to it. EPA should address this fact*
* The record demonstrates that combined effects of
combustion modification is less than the sum of each
individual effect.
2-152
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Adequacy of the Nitrogen Oxides Data Base
1. D-203
Comment: NOX data for shale oil combustion is1not available. More
tests .are needed*
2. D-145, D-491, D-519, D-611
Comment: Study needed to determine fuel-bound NOX percentage of
emissions. Bituminous coal about 23% higher in fuel bound
nitrogen than subbituminous coal.
3. D-458 . . -.
Comment: EPA data was collected with an uncertified continuous
monitor at one boiler. This is hardly justification for
all boilers on a continuous basis. ' •
4. D-491, D-519, D-611 • • '
Comment: Question test information on record. Information was not
complete with respect to: type of operating conditions
(representative, long term, load; load follow, fuel type),
reference method, number of•tests/instance,'time period
covered, number'rejected '(and why), check-for stratifi-
cation, chemical analyses "for reference 7, steady state
or not, normalized using F-factor or fuel analysis, fuel
samples used for F-factor.
2-153
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5. D-491, D-5L9, D-611
Comment: EPA did not evaluate enough boilers subject to current
NSPS standard.
* Survey indicates that tio boiler subject to current NSPS
can meet 0.6 Ib/aillion Btu on a. range of bituminous
coals*
* Only two performance tests on two of five boilers
subject to the current NSPS and burning bituminous
coal met a 0.6 lb/million Btu standard.
6. D-491, D-519, D-611
Comment: Data base for evaluating continuous NOX emissions was
inadequate.
* Short term results can be run with atypical configura-
tions. EPA admits some of its data reflect this mode
of operation;
* Virtually no continous NOX monitoring data exist on
boilers subject to the current NSPS;
With respect to the Colstrip continuous monitoring data:
• Data used to set standard collected prior to shakedown.
New data show results above proposed standard;
* Data only from a tangential boiler;
• Used only one subbituminous coal type;
• No load variation data or supportive performance test
results used;
* Uncertified data.
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Averaging Time for Nitrogen Oxides
1. D-223, D-232
Comment-: Supported 30 day averaging as a minimum reasonable averag-
ing time (no supporting documentation was given).
2. D-4133 D-421, D-4613 D-519, F-lu
Comment: Data presented does not support use of 24-hour averaging.
2-155
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Relationship of Nitrogen Oxides with Other Pollutants
1. D-L56, D-2183 D-491, D-519, F-la
Comment: Particulates may increase under the proposed NOX
standard*
2. D-491, D-519, D-611
Comment: CO increases due to iow-HOx operations,
* Table 6-3 of EPA 450/2-78/Q05a (NOX Background
Document) shows ten fo
emiseioas are reduced.
Document) shows ten fold increase in CO as NOX
* Even with tangentially fired boilers, data on Pages
6-14 and 6-15 shows five fold increase in CO,
2-156
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Nitrogen Oxide Cost Analyses
1. D-491, D-519, D-611
Comment: Cost Analyses
• Scenario I (most likely) does not take into account
EPA'a own judgement that all boiler-types are not
equally effective. In addition, costs for R&D,
premiums on guarantees, maintenance and replacement
power coste due to corrosion, risk due' to accidents
under low-NQx conditions, reduced unit efficiency,
and each boiler type/fuel combination have not been
performed adequately.
* Scenario II ignores time and relative financial and
technological base of manufacturers to develop new
low NOX systems (or burners). In addition, time
delays could force one or both manufacturers out
of the market. It is also suggested that the ratio
of cost to net income from boiler sales would have
shown a different result as to impact of burner de-
velopment on one manufacturer*
• Scenario III assumptions are unjustified and ignore
the fact that utilities would not risk buying a new
tangential boiler design from a manufacturer who had
never built or fully tested one before. This will
tend to increase the anticompetitive effects of the
regulations by driving boiler manufacturers out of
the market.
2. D-491, D-519, D-611
Comment: Proposed standard may cause increase in use of subbitu-
minous coal since 0.6 lb/10° Btu bituminous coal NOX
standard may not be achievable.
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Nitrogen Oxide Safety Issues
1. D-491, D-519, D-611
Comment: Indication of flyash carbon carryover doubliag in the
low-NOK mode has safety as well as efficiency and
particulate emission implications.
2. D-491, D-519, D-611
Comment: • No risk assessment made of continued low-NOx
operation. Tests were performed with trained test
engineers over short time periods.
* Not enough margin of flexible operation (e.g., excess
air).
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2.5 Testing, Monitoring, and Reporting
2.5.1 - 60t46a Compliance Provisions
Compliance Testing
1. D-168, D-259, D-464, D-491
Comment: EPA must properly validate its test methods and provide
information on the overall accuracy of those methods when,
used to measure particulate emissions from fossil-fuel-
fired electric utility steam generating units at the 0.03
lb/106 Btu level.
2. D-631
Comment: Failure to require compliance testing for percent reduction
of particulate is a direct violation of section 111 of the
Clean Air Act. Adequate technology for such testing
exists.
2-159
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Startup, Shutdown and Emergency Bypass
1. D-223
Comment: No provisions are made for exemption of particulate during
startup, shutdown and malfunction,
2. D-320, D-410, D-438, D-477, D-483, F-ly
Comment: The emergency bypass provisions should be more lenient.
In addition3
* determination should be made on the basis of those
on line at the time of occurrence,
* cold starts for turbines should be exempt under these
provisions
3. D-156, D-168, D-250, D-523
Comment: A more lenient emergency bypass provision is needed
because:
• unreliable scrubbers will require it
* costs to meet present provisions are substantial
* impact of looser provisions on air quality is
negligible.
4, D-253, D-488, D-491
Comment: Section 60, 46a(d) (2) would require operating a FGD module
until it is completely inoperable before it can be
bypassed. This could cause major damage to it in some
cases. It is recommended that the word "malfunctioning" be
substituted for "totally inoperable" and malfunctioning
defined as a reduced efficiency or capacity of a module.
2-160
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5. D-4.15
Comment: The emergency bypass provisions should be guidelines rather
than rigid rules.
6. D-523
Comment; One of the conditions for S02 bypass operations is to
install a spare FGD module. There is an apparent
contradiction in the size of unit requiring a spare
module: the preamble cites > 125 MW heat input (43 FR
42159) and the proposed regulation states > 365 MW heat
input (43 FR 42176).
7. D-491
Comment; Section 60.46a(d) should be clarified by changing the
phrase "continue operation" to "be operated". This will
allow a malfunctioning unit to be brought on line during
an emergency or projected emergency as opposed to the
current meaning which would only allow an on line unit to
continue.
8. D-611
Comment: The proposed requirements of 40CFR60.47a(a) would allow
alternative methods in place of a transmissiometer to
assure that particulate control equipment is properly
operated and maintained. The requirement for reporting in
§60t49a(e)3 however, appears to preclude the use of other
methods, such as monitoring particulate matter control
2-161
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equipment parameters. Since the single intent of opacity
monitoring, e.g. 43F142172, is to assure that particulate
control equipment is properly operated and maintained, the
alternative methods should not be foreclosed.
2-162
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2.5.2 - 6Q.47a Emission Monitoring
General Comments on Emission Monitoring
1. D-206
Comment: Paragraphs 60.47a(a), (b), (c) and (d) should be reworded
as follows; "The owner or operator of an affected facility
shall install, calibrate, certify, maintain and oper-
ate...", if the intent is to require individual on-stack
certification of continuous monitors as presently required
under 40CFR60, Subpart D. Subparagraphs (b), (c), and (d)
should- be similarly modified. There are several changes
and clarifications required to make your instrument
certification procedures both effective and useful, how-
ever, it is presumed that this type of regulation will be
addressed separately and/or possibly under Appendix E,
• which has been reserved for quality assurance provisions.
2, D-206, D-611
Comment: In paragraphs 60.47a(e) and (f) a greater amount of time
per day should be allowed for calibrations and routine
maintenance for reasons stated below, "All continuous
monitors are required to have their calibration checked at
least once daily. Your allowance here of one hour per day
seems adequate, although with our current instrument, this
would limit the automatic calibration cycle to once every
two hours, and current practice shows many operators are
selecting an hourly calibration check interval. In this
2-163
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instrument each calibration value requires one minute, and
there are four values to be determined: S(>2 zero, S02
span, NO zero, and NO span. As a result, each complete
cycle .requires four minutes. I believe that the allowance
could be made larger, but it should be noted that the cal-
ibration time allowance need not be considered as downtime
from a data availability standpoint. For short calibration
intervals, there is no substantial data degradation if one
was to interpolate the actual measurement value during cal-
ibration by averaging the measurements before and after the
calibration, cycle."
3. D-206
Comment: Under paragraph 60.47aCe) no provision is made for develop-
mental testing of new instruments or configurations. "In
the area of FGDS, you have proposed a commercial demonstra-
tion permit concept, and I believe a similar provision -for
new promising instrumentation would help to assure the
acceptance and development of new and improved equipment.
Your current proposal only penalizes any"operator who would
like to cooperate with a vendor in the evaluation of new
improved instrumentation^ and such developments are needed
in this area of application (FGDS)."
2-164
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4. D-206
Comment: Under 60.47a no provision is made for non-routine mainte-
nance of continuous monitors. "Certainly your provision
for mandatory manual stack sampling is not a realistic
alternative to non-routine maintenance of the continuous
monitors. We believe that the requirements for this
activity during monitoring system downtime is a totally
unworkable solution. This conclusion is based on the
following:
» The training required to obtain dependable results.
t The loss of competence associated with occasional use
of the skills.
• The near impossibility of paying people enough to keep
them involved in this activity and to make them "climb
the stack."
« The often near impossible working conditions — at
nightj in the winter, during snowstorms, rainstorms,
thunderstormsj or windy conditions.
We firmly believe that some realistic allowance must be
made for anticipated monitoring system downtime or non-
routine maintenance.
5. D-206
Comment; The commentor feels that the eight hours per month for
routine maintenance allowed under paragraph 6Q«47a(e)(2)
is inadequate for anything but a standard non-wet scrubber
application for following reasons: "It should be noted
2-165
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that wet scrubber FGDS also present a very difficult mea-
surement environment. With your proposed SC>2 emission
limits, it is doubtful that any untreated bypass gas can
be blended into the scrubber effluent and with the cost of
reheat rapidly escalating, the actual gas temperature and
dewpoint temperature will be equal. This means that any
slurry carryover or demister discharge will remain as en-
trained water droplets and pose a real blockage threat to
inacack filters, which are typically used in extractive
and short-path in-situ gas measurement systems. Even
long-path or across—stack insitu systems are bothered by
such entrained water if not from a gas restriction stand-
point as a threat to light transmission, as the drops ab-
sorb and scatter the measurement light beam."
6. D-206
Comment: The required measurement ranges shown in subparagraph
60,47a(g)(5) vary too widely for simple, reasonable in-
strument performance. "The number of required measure-
ments ranges should be restricted to something like a 3
to 1 range, for example, 500, 1000, and 1500 ppm, within
a single instrument configuration to ensure instrument
performance., simplicity and reasonable price. Most current
instruments also include only a single span cell or refer-
ence value device which is used to verify the upscale cal-
ibration. Unless you wish to change this current practice,
2-166
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the requirement to change ranges frequently should be
avoided, or minimized."
7. D-206
Comment; The opacity span value of 60 to 80% shown in paragraph
60.47a(g) should be changed to a simple round figure type
of scaling. "We believe the range should be expanded to 50
to 80% for stack exit opacity indications which would allow
at least one (501) round figure selection. Current
instruments which would be used for such applications have
full scale ranges of 10, 20, 30, 50 and 100% opacity,
corrected for stack exit conditions."
8.. D-288
Comment: It is not clear whether downstream 862 monitors can be
located after particulate collector to take advantage of
any S0£ absorption on collected particulates.
9. D-455
Comment; In 60.47a(g)(5), the requirements .for determining the span
values for the analyzers will result in nonstandard spans.
Most instruments have standard ranges such as 0-500 ppm,
0-1000 ppnij etc. There is also a requirement that the span
of the analyzers be changed when, the fuel sulfur changes by
0.5 percent. This is totally impractical since fuel analy-
sis results are not known until 2-3 days after the fuel is
burned. It is suggested that analyzer spans be determined
by the anticipated S02 concentrations. The analyzer
2-167
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range could then be rounded off to the next 500 ppm higher
range to ensure that the analyser would operate on-scale.
10. B-436, D-611
Comment:
* 98.9% requirements for data availability are not
justified with respect to current technology.
• 90-95% capability is based on limited experience and
factory authorized maintenance and on-site spare parts.
* EPA should reviae 8-hour maximum in 60.47a(e)(2).
• more detail is required on back-up system requirements
(e.g., calibration, running tirae3 etc.) since they can-
not be turned on in an emergency.
11. D-218
Comment: Lack of a continuous monitoring instrument for particulates
will cause enforcement problems.
12. D-611
Comment: The proposed procedures for monitoring system performance
evaluations and calibration checks for SC>2 (Section
60.47a(g)(5)) are unrealistic because,
• continuous monitors should be calibrated at span
concentrations which more closely correspond to the
expected operating conditions
* sources will be unable to comply with the S02
respanning requirements since they will have no means
of determining when the S(>2 concentration in the fuel
changes by 0.5 percent or more
• many state-of-the-art continuous monitors are incapable
of being respanned.
• EPA .has not developed a protocol or quality control
quidelines for NBS traceable gases and has not
2-168
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prescribed adequate methods for sampling from gas
cylinders.
13. D-588
Comment: Paragraph 60.47a(d) implies that C02 is an acceptable
diluent parameter for FGD without supporting data. The
October 6, 1975, Federal Register specifically discourages
C02 as a diluent measurement downstream of lime or lime-
stone FGD.
14. D-588
Comment: If the following assumption is corrects it is requested
that the statements listed below be clarified: "re-
quirements for instruments on FGD's will agree with re-
gulations set forth in the October 6, 1975, Federal
Register."
• A complete 302 analysis every 15 minutes is deemed
continuous. This should be retained in that up to six
FGD points can be measured with multiplexing
instruments, thus reducing capital costs.
« Certification vs. an approved instrumental technique
should be permitted. Instruments that are more
reliable than Method #6 are commercially available.
* An alternate means of certifying FGD instrument
performance should be permitted since field performance
testa are too costly and time consuming,.
* Multipoint (multiplexing) instruments have been used
extensively on experimental FGD's in actual field
operations. Depending upon the time during which span
gases are introduced during an analysis cycle, upscale
and downscale response can vary by more than 15%. As
long as the instrument is capable of responding within
the portion of the fifteen minute cycle deemed
2-169
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continuous for each sample point (in both directions)
this requirement appears redundant.
October 6, 1975, regulations are written such that they
promote (actually favor in our opinion) the use of
in-situ instruments because span gas introduction is
not required and because of the requirements to measure
SC>23 NOX and Opacity (which can be accomplished
with a single instrument). This of course is cost
effective, but the FGD problem is different. Here, the
instrument is being used to calculate S02 removal
efficiency and absolute S(>2 in the final effluent.
Consequently, we believe that ail instruments should be
subject to the same requirement (i.e., use of span
gases). This is especially important since certain
in-situ monitors have been improved such that zero air
can be introduced. If this can be done, it leads one
to believe that span gases can also be introduced.
Moreover, in the case of FGD's, multipoint instruments
in many cases will lead to the most cost'effective
approach. Alternately, calibration standards can be
written that permit optical calibration for extractive
or in-situ devices using gas bottle filters. Since
diluent measurement is required in EPA1s September 19,
1978, proposal on inlet and outlets. The need for span
gas introduction at probes is not needed.
Most instruments used to measure SC>2 in steam
generating plants measure on a wet basis and correct
for moisture to calculate Ibs. per 10^ Btu. An EPA
representative reported success with moisture
estimation at the Battelle Institute FGD Symposium held
December 12, 1978. Here, a multipoint S02 analyzer
was used and moisture was estimated from condensate
trap temperature measurement. We believe this to be a.
viable approach and especially since we know of no
instrumental method in sufficient wide use that can
measure with 1.5 percent accuracy.
2-170
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Monitoring Instrument Accuracy
1. D-256, D-259, D-477, D-491, F-lx
Comment: There are no data to prove continuous monitors perform
accurately.
2. D-471
Comment: Experience with monitoring instrument accuracy
specifications is +_, 20% relative to imprecise manual
methods. ._
3. D-588
Comment: In favors of multipoint 862 instruments because a multi-
point S02 analyzer calibrated improperly and having a 20
percent variance from Method $6 due to either a high or low
reading would still provide data from which FGD removal ef-
ficiency could be determined. Whereas, two single point
instruments of the same or different manufacturer could
still be certified with a +20 percent error and a -20 per-
cent error. In this case, instruments would not provide
data suitable for determining FGD SC>2 removal efficiency.
2-171
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Monitoring Instrument Reliability
1. D-153, D-168, D-256, D-2G5, D-373, D-397, D-425, D-467, D-476,
D-477, D-491, D-585, D-657, F-lb; F-lg, F-lw, F-lx, F-2
Comment: Continuous monitoring equipment is unreliable and serious
problems exist in complying with the standard.
2, D-206
Comment: System reliability would be much higher if dedicated
instruments were used at each measurement point rather than
any other type of multisensor/stngle instrument approach.
3. D-206
Comment: Continuous monitoring system reliability is not dependent
on just the reliability of a single element. "One must
consider all the identificable and required elements
involved in a system — this includes the pollutant mon-
itor, diluent monitor, computerized data logger and proces-
sor and I/O terminal. Strip chart recorders are also
involved in manual data collection systems. In a four-
element system with each element possessing a reliability
of +90, the overall reliability is only 66%."
4. D-263
Comment: The commenter operates name brand continuous monitoring
equipment which is usually operational only 5 days out
of 30. Typical down time is 95Z. The cost estimate for
hourly manual sampling under these conditions would be $1.5
2-172
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million per year. The reliability of continuous monitors
must be improved and/or the manual sampling requirement
relaxed or deleted entirely.
5. D-464, F-2
Comment: Redundant monitoring systems frequently do not improve sys-
tem reliability since backup monitors often fail at the
same time as the on-line system (e.g., after a lightning
strike).
6. D-471
Comment: The following comments regarding monitors are submitted:
» Opacity monitors installed in September 1977 have.yet
to operate successfully. Microwave interference is
suspected. The point is one of uncertainty as to
capabilities of devices under varying conditions.
» Experience with monitors has been disappointing with
regard to malfunctions.
7. D-626, F-lw, F-lx
Comment: The court held in Portland Cement vs. Ruckelhaus 486F 2d
375 (DC Cir. 1973) that a monitoring requirement which, is
part of a standard, violation of which can result in an
immediate enforcement action must be demonstrably
reliable. If continuous S02 stack monitoring is not
technologically feasible nowa that method can be used as
an alarm system with follow up by manual testing.
2-173
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Continuous Monitoring
1. D-224, D-2S3, D-256, D-259, D-287, D-440, D-447, D-458, D-459,
D-463, D-464, D-488, D-490, D-498
Comment: Continuous monitoring with no exceptions is unjustified
and unrealistic based on costs,"manpower and/or state—of" ~
the-art of instrumentation. It does not improve emissions
in any significant way.
2. D-253
Comment; Section 6Q.47a(e3 appears to make part (f) inapplicable
unless (f) is made subpart (3) under (e).
3. D-300
Comment: At least 24 hours per month should be allowed for routine
maintenance.
4. D-411
Comment: In favors of continuous monitoring
5. D-455, D-491, D-611
Comment: The requirement to determine compliance with SC>2 and
NOX emission limitations and with the SC>2 percentage
reduction by using continuous monitors is unrealistic
because,
* This is a new, unproven technique
• Continuous monitors are neither reference methods,
equivalent methods nor alternate methods
• Allowed and inherent inaccuracies of continuous
monitor data preclude their use for compliance
determinations. These inaccuracies include:
2-174
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(a) allowed inaccuracies of pollutant monitors,
relative to reference methods
(b) inaccuracies of diluent monitors
(c) allowed errors due to installation of monitors at
other than ideal locations
(d) degradation of monitors with time
* Allowable inaccuracies may reach +_ 35 percent,
• Monitor accuracy is extremely critical when determining
compliance since many sources will operate near
compliance levels.
6. D-463
Comment: The most sensible approach for Western utilities to de-
termine whether they are in compliance with the percentage
reduction requirement for SC>2 emissions is the "as fired"
basis found in proposed section 60.47a(b)(3). This option
should be retained because EPA1s analyses of the benefits
of the "as fired" sampling technique is correct.
7. D-631
Comment: In favor of the real time transmission of monitoring and
scrubber data to EPA to monitor performance levels.
8. D-611
Comment: The accuracy and precision of the two methods for
conducting performance tests differ. The difference
between the results obtained by initial performance tests
and continuous monitors can be significant. The proposal
does not specify which method takes precedence.
2-175
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9. D-611
Comment: The proposal requires that continuous monitoring comply
with the performance specifications of Appendix B of
40CFR60 yet,
• nearly one-half of all continuous gas monitors which
have been subjected to Performance Specifications Tests
have fail.ed
* a typical generating unit, employing parallel scrubber
trains and ten gas monitors, may have less than a 1
percent chance of all monitors passing the initial
performance tests
10. F-lc
Comment: If continuous monitoring is of questionable feasibility at
present3 it should be deleted from the present standard and
promulgated later as part of a separate regulatory process.
2-176
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Backup Manual Monitoring
1. D-168, D-205, D-212, D-215, D-216, D-224, D-227, D-232, D-253,
D-256, D-259, D-263, D-272, 0-300, D-322, D-397, D-401, D-404, D-407a
D-413, D-417, D-423, D-425, D-437, D-44Q, D-444, D-449, D-455, D-458,
D-464, D-467, D-471, D-476, D-486, D-488, D-491, D-611, F-lx
Comment: The proposed regulations for monitoring when continuous
monitors are not operable are unreasonable. One or more of
the following reasons were cited by each commenter.
• It requires several hours to set up for the first
sample even if a standby crew is on duty. It may
go beyond a full day if the facility does not have
an in-house test crew. A lag time is needed before
first test is required,
* Simultaneous failure of more than one monitor com-
pounds the problem,
• Failure of a monitor does not•in itself indicate fail-
ure of control equipment.
* Hourly tests are unreasonable and impractical. Manual
tests should be deleted entirely or required only one
or two times per day.
• Sampling from a stack is almost" impossible in severe
weather. There should be-'sorae exceptions.
- •' This requirement is extremely unjust for small utili-
ties.
» Test results are not available in time to provide
useful feedback.
2. D-366 . • , • ,
Comment:' A requirement "for minimum downtime is more appropriate
than hourly manual testing.
2-177
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3. 0-366
Comment: Particulate testing when an opacity monitor, is down is.
unnecessary.
4. D-366
Comment: Since there are no control devices for NOX emissions,
what will manual testing accomplish?
5. D-366
Comment: S02 testing at the inlet is unnecessary during downtime.
6. D-206, D-215, D-227
Comment: The log of critical operating parameters should be used in-
stead of manual backup for continuous monitors. The re-
asoning is as follows; "For example, a typical wet scrub-
ber FGDS can be reliably evaluated from a knowledge of
pressure drop, pH, slurry feed rate, make—up water feed
rate, damper positionsa etc. Therefore, we would recommend
that such critical parameters be continuously monitored and
used for proof of compliance during periods of instrument
downtime as an alternate to manual sampling. Even if the
absolute readings at any given point in time are not total-
ly conclusive, the relative indications occurring with
known emission levels priorto instrument failure can be
correlated with operating conditions during the time the
instrument is down to ensurethe continuous and reasonable
operation of the controlequipment during this time.
2-178
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Certainly, with moderncomputerized data logging and report
generation systems,it isa fairly simple and inexpensive
matter Co monitor andrecord such additional process
information."
7. D-627
Comment: In view of the unreliability of monitors and the expense
. ' of continuous manual backup, none of the alternatives for
meeting the continuous monitoring requirements is viable.
Up to 3 hours outage of continuous, monitors should be
allowed for on-site repairs followed by manual testing on
a 3 hour schedule.
2-179
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2.5,3 - 60.48a Compliance Determination Procedures and Methods
1. D-223
Comment: Change the title of 60.48a to "Performance determination
procedures and methods" to differentiate between per-
formance testing and ongoing compliance tests.
2. D-404, D-413, D-417, D-455, D-458, D-486
Comment: The regulation should specify that particulate matter is
measured immediately after the particulate control device.
This is related to comment 6 on the particulate matter
emission limit (D-153).
3. D-438, D-448
Comment: Compliance should be determined by performance tests under
existing EPA reference methods»
4. D-455, D-491, D-611
Comment: There is a way to ensure compliance with standards without
the reliance on inaccurate, unreliuable monitors. The
monitor performance specifications were written to apply to
"indicators of control device performance." Monitors can
be retained for the purpose of indicators. SC>2 and NOX
analyzer data could then be handled like opacity data.
Indicated excess emissions or low removal efficiency could
be reported quarterly. Based on these data, the agency
could request a formal compliance test if necessary. The
effect would be to require compliance of the FGD system on
2-180
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a short-term basis where indication of continuing
.compliance could be demonstrated on a long-term basis with
monitors as is now being done for parliculate control
devices.
5, D-455, D-611
Comment: .A much simpler way to indicate compliance is to determine a
monthly average fuel input sulfur, apply the fuel cleaning
credit, and monitor S(>2 emissions out of the scrubber.
This procedure, would eliminate unnecessary monitors and
fuel sampling and would therefore be subject to fewer cumu-
lative errors.
6. D-467
Comment: Exemptions during startup, shutdown, etc., fail to provide
for certain operational startup activities such as balan-
cing of the turbine generator.
7. F-lb
Comment: Because of the unreliability of monitoring equipment and
the undue cost of continuous monitoring, the provision
should be eliminated. Continuing compliance should be
enforced by performance testing on a spot-check basis* If
the continuous monitoring provision is to be retained, then
a standard should be placed on manufacturers of monitoring
equipment to guarantee the required high reliability.
2-18L
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8. D-611
Comment: The proposed standard requires that daily emission values
are determined as the arithmetic average of the emission
measurements derived either from continuous monitors or
manual methods. EPA has not presented an adequate analysis
of the biases associated with arithmetic averaging of
emission values as opposed to proportionally weighting the
emission values with respect to production rate parameters.
This may be important if scrubber performance varies with
electrical load factors.
2-182
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2.5.4 - 60.49a Reporting Requirements
1. D-223, D-250
Comment: Report requirements should be limited to either the monthly
average or a simple report of,periods of excess emissions.
2. D-223, D-263 • . -
Comment: The cost of data reduction and reporting is not given. Was
it considered? For example a typical small computer would
• cost from §35 to $75,000.
3. D-322
Comment: Utilities are responsible for compliance. However, they
should not be responsible for identifying excess emissions.
Unless there is a logical use for the reports, they should
not be required.
4. D-256
Comment: Section 60.49a(f) should allow at least 45 days for
submission of a report. Extra personnel on" shifts are
unjustified.
5. D-206 '
Comment: There are several related areas where the contents of
section 6Q«49a need clarification or revision.
6. B-588
Comment: No maintenance or downtime should be charged to an
instrument when the FGD module is down since it is an
opportune time to perform maintenance and calibration.
2-183
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7,, D-611
Comment: In the preamble to the proposed Subpart Daa EPA currently
states that opacity readings taken before and after a FGD
system' will not necessarily provide the same results and
that opacity monitoring should not be used as a compliance
determinant with the out—of—stack opacity standard. These
statements are not explicitly reflected, nor directly
implied, in the proposed Subpart Da itself. The ambi-
guities in the reporting requirements of section 60»49a(e)
imply that reported transmissometer data might be used for
opacity compliance determinations5 since excesSemission re-
ports derived from opacity monitors output must be in terms
of the standard*
8. D-627
Comment; The requirement for emission monitoring data is
unreasonable in terms of workload on plant personnel and it
will far exceed EPA's ability to store, retrieve and
review. EPA should require reporting of the data on a "by
exception" or occasional basis only—e.g.3 when required
for EPA's specific use, on a fixed schedule, or by a random
sampling approach.
2-184
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2,6 Appendix A, Reference Methods
1. D-179
Comment: Requirements to use EPA Method 19 with no provision for
new techniques is unreasonable.
2. D-224
Comment: The method for analyzing daily "as burned" fuel is too
complicated.
3. D-247
Comment; For Methods 5 and 17, the standard should stipulate "dry
filter catch only" due to the fact that much of the
emissions is in the vapor state while going through the
particulate control device.
4. D-280
Comment: Stack testing for S0£ should be eliminated if pretreat-
ment is the only control used.
5. D-404
Comment; The test methods for particuiate matter do not appear to be
applicable to testing in the ductwork between particulate
control and scrubber.
6. D-437
Comment: Question the hourly sampling of coal (200 Ib/hr by ASTM
standard).
2-185
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7. 0-440
Comment: Question the 24-hour lot size in paragraph 3.3, Appendix A
when paragraph 2*1.2 allows a 90-day lot size. Question
the burden of analyses on a 24-hour basis.
8. D-455
Comment; There are no procedures to account for the fact that a
plant might receive some precleaned fuel and some that is
not precleaned. In the Method 19 calculation procedure,
each lot of coal has the same mathematical weight regard-
less of the lot size. Under the proposed procedure, one
could receive a one-car lot of precleaned coal and apply
that credit to all coal burned for a 3—month period*
Fuel precleaning credits should he determined on a Btu-
weighted basis.
9. D-455
Comment: Method 19 does not qualify as a reference method since it
is only a calculation procedure. It does not stand alone
since it continually refers to subparts. If it is to be a
reference method then it should stand alone, and an analy-
sis of the total error should be performed on the Method.
I would think that one would be surprised if this is done
since I have estimated the error to be in excess of 501
because of monitor aad fuel analysis errors.
2-186
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10. D-455
Comment: No mention is made of the fact that certain scrubbers
absorb C02 and that this can cause significant F-factor
>:rrors. This should be addressed.
11, D-455
Comment: It is stated in Method 19 that since reheaters only require
from 1 to 2 percent of the total heat input of the boiler^
their effect can be ignored. Unfortunately, direct-fired
heaters are notoriously poor combustors and introduce
significant stratification3 usually close to the sampling
point. Sampling should not be done downstream of a direct-
fired reheater unless the gas is well mixed.
12. D-4713 D-491
Comment; Question the accuracy of Methods 5, 6, 75 and 17 at the low
emission levels of the standard.
13. D-206
Comment; EPA1s attention was focused too tnuch on the theoretical
accuracy of the various test methods rather than practical
accuracy.
14. D-588
Comment: In general, all requirements are stated in terms of 24-hour
averages. Can it be assured that the +^ 1.5 percent
allowable error discussed in 5.3.1.2 on page 43 FR 42182
refers to Bws derived data averaged over a 24-hour period?
2-187
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L5» D-588
Comment: The applicability of equations in Section 5.3.2 should be
restricted to data obtained upstream of a flue gas d'esul-
furization system.
16. D-611
Comment: Under Method 19, methods for determining heat input rates
for the various fuels are not specified.
17. D-611
Comment: Method 19 does not specify the frequency of calculating
F-factors. The conditions under which the F-factor must
be recalculated should be identified so that the accuracy
of the emission or percentage reduction calculation can be
determined.
2-188
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2.7 Economic Impacts
Cost to Consumer
1. D-117, D-152, D-157, D-169, D-198, D-29Q, D-462, F-lc, F-li,
D-631, F-lt
Comment: In favor of full scrubbing, a low ceiling or cap (maximum
emission level), and/or a percentage reduction in S(>2
emissions equal to or greater than the 85 percent proposed
on one or more of the following grounds.
* cheap power is impossible, prefer to pay now
» strict standards will promote use of local coal
* utilities should pay the full cost of burning coal
* 2 percent of capital costs or 48 cents/month in household
bills for control is not unreasonable
• will create more jobs and improve the economy
• alternative power sources will become more competitive
* survey in one locality showed consumers are willing to pay
for clean air
• San Juan (New Mexico) Generating Station scrubber achieves 90
percent, requires only 4 percent of total input energy, and
produces a marketable product
• partial scrubbing gives artifically preferential treatment
to low-sulfur coal
2. D-22, D-28, D-3i, D-34, D-40, D-62, D-64, D-88, D-90, D-100,
D-114, D-132, D-145, D-150, D-153, D-167, D-168, D-216, D-223, D-224,
D-225, D-232, D-234, D-237, D-238, B-242, D-244, D-251, D-252, D-259,
D-261, D-263, D-265, D-267, D-270, D-271, D-274, D-276, D-279, D-284,
2-189
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D-286, D-287, D-289, D-294, D-297, D-298, D-299, D-300, D-303, D-317,
D-319, D-322, D-329, D-332, D-334, D-340, D-344S D-346, D-347, D-348,
D-349, D-368, D-370, D-403, D-404, D-405, D-407, D-418, D-4215 D-422,
D-431, D-4573 D-458, D-466, D-467S D-474, D-491, D-4983 F-ls3 F-lz,
F-ly, F-lx, F-laa, D-514, D-523, D-598, D-5993 D-600, D-625, D-6283
D-634, D-635, D-639, D-6423 D-643, D-667, D-670, D-674, D-682, D-&83
Gomoent; Oppose the regulation as proposed; prefer no change in cur-
rent standards or partial scrubbing with sliding scale
and/or higher floor as proposed in DOB and UARG alterna-
tives. Proposed regulation opposed for one or more of
following reasons:
* too expensive
* retail pover cost increase of 4 to 13 percent in a particular
utility
* estimate increase from present $6.08 to $12.05/customer/month
for controls at a particular plant
• not cost effective in terms of cost per ton of S02 captured
• inflationary
» cost to consumer could reach 20 percent of hill in particular
situations
* counter-productive (full control may produce more S(>2
emissions than partial control)
• discourages use of coal and increases use of oil
* decreased economic growth opportunities in Western coal
producing states
• economic studies neglect secondary effects on state
regulations, ripple effect through economy
2-190
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* question whether model capability can assess economic impacts
within a region
• sludge costs of $19/Mg underestimated by factor of 2 to 4
* opposes stating effect in terms of monthly cost to consumer
a? this neglects pass through costs from industry
* inequitable regional impacts
3. D-303
Comment; S02 standard hurts New Mexico coal industry.
4. D-270
Comment: Regulations provide incentive to continue with oil and gas
plants.
5. D-254
Comment: Concerned about the multiple effects of all rules on
economic growth and resource development.
6. D-262, D-418
Comment: The economic model understates the relative costs of full
scrubbing.
* Marginal costs increase disproportional to benefits with
increased standard
* Understatement of Wyoming Powder River Coal Reserves
(estimated 15 billion tons recoverable)
* No sulfur credit in model for washing coal
• Oil prices projection is too high
* Inflation rate is too low
• Time horizon in the analysis is too short
2-191
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* Assumptions are not adequate3 specifically,
- Does not obtain total system capacity requirements based
upon reliability criteria
- Does not simulate utility operations, i.e., does not carry
out hour-by-hour dispatch and assumes the same number of
spare scrubbers for full and partial scrubbing whereas the
number should be based on reliability analysis
- la more sensitive to the price of oil (alleged not to be a
major consideration, in utility operations) than to floors
(maximum sulfur content at which scrubbing not required)
- Should have used a range of values for electric growth and
discount rates since there is no consensus on what these
will be
- No analysis of 30-day averaging of emissions
7. D-473
Comment: For the Edgewater V facility in Wisconsin, costs of the
proposed controls were calculated to be $319.4 million in
1983 dollars with a maximum ambient air quality improvement
of 5 percent over what would be achieved with the use of
low sulfur coal.
8. D-479
Comment: Both transportation and labor costs are stated as projected
to increase at a rate 1 percent above the assumed rate of
5.5 percent. Federal strip mine regulations, effective
January 19793 are cited as increasing coal production
costs.
2-192
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9. F-lc
Comment: The economic model is deemed to overstate the relative
costs of full scrubbing for the following reasons:
• Substitution of oil for coal because it is cheaper will not
be allowed and should not be provided in the model
* Reduction of SC>2 emissions under other requirements (such
as PSD and SIP) should not have costs charged to revised NSPS
10. F-ly
Comment; The national average of economic impacts on consumers is
tnisrepresentative. The heaviest burden will be felt by
fast-growing utilities and in regions such as the West
which are experiencing and will experience higher growth
rates.
11. D-611
Comment: Calculations by the National Economic Research Associates,
Inc. show the annual costs of proposed revisions higher by
from 2.1 to 2.5 times those calculated by the model EPA
reported in the Federal Register. Also the incremental
costs of full scrubbing over those of a sliding scale are
projected to be higher. The differences appear to result
from assumptions regarding a higher growth rate in demand
for electricity, scrubber reliability, and particulate
control costs. When these are adjusted to reflect more
nearly the assumptions in the ICF, Inc. model reported by
EPA the results are closer but costs of full scrubbing are
still higher as calculated by NERA.
2-193
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These differences also affect estimates of the cost per
ton of S02 removed. Depending on whether or not greater
scrubber reliability and lower electricity growth rates are
assumed the costs may be less than those reported by EPA or
even higher.
Electricity demand growth rate averaging 4.4 percent
per year used by ICF Inc. in August runs reflects an
overreaction to increased costs and is too low. Prefer 5.3
percent annually through 1990 5 as used by NERA,
Models typically calculate minimum costs; hence, the
IGF Inc. model probably underestimated actual costs.
12. D-491
Comment: The proposed regulation for full scrubbing is not cost
effective when compared with the alternatives for a sliding
scale proposed by UAKG and DOE, Full scrubbing would
achieve a 16 percent reduction in S02 emissions at a 54
percent increase in costs. In terms of additional S02
removed, the incremental cost per ton under full scrubbing
is $2500 over the DOE proposal and $1333 over the UARG
proposal. A recent (1975) study by the National Academy of
Science estimated the benefits of S(>2 removal to be $200
per ton. This study included health benefits not at issue
here. The cost per ton of 862 removed under full scrub-
bing is 4 times that under partial scrubbing.
2-194
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13. D-625
Comment: Scrubber technology has been determined by EPA as mature.
Therefore the assumption of declining capital costs for
controls used in the model are unrealistic and understate
both the incremental and total costs of full scrubbing
relative to partial sampling.
The scrubber reliability figures and the operating and
maintenance - costs used in the model do not reflect the
performance levels actually achieved. Consequently both
the costs and the SC>2 emissions (resulting from inability
to achieve 100 percent compliance) under full scrubbing
will be greater than those projected by the model.
14. D-514
Comment; It is unlikely that midwestern coal will keep pace with
demand so western coal will eventually be used anyway.
15. H-13
Comment: The shifts in the price level resulting from the one
regulatory action of revised NSPS (increase of 0.6 percent
to 1.1 percent by 1990 and by from 1.2 to 2.1 percent by
1995) are seen as having considerable effect on the
national economy and no significant differences in benefits
appear among the analyzed options.
16. F-lr
Comment; In some Appalachian states, the model projects that coal
production will actually decrease from the 1975 level under
2-195
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EPA, DOE and UARG proposals. This is not fully credible
and casts doubt on the model.
2-196
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Cost to Other Industries
1. D-5, D-163, D-191, D-233, D-4223 D-452, D-4543 D-478
Coininent: The proposed standard with full scrubbing is inflationary,
having higher marginal costs than the alternative proposals
that call for partial scrubbing. These costs will adverse-
ly affect industry, especially metals and mining.
* Percent increase of marginal costs of electric generation
above current NSPS is 15.08 under full scrubbing, compared
with 10.56 and 7.48 under the partial scrubbing alternatives
proposed by DOE and UARG respectively.
• 40 percent of electricity is used for manufacturing
• Detrimental effect of full scrubbing on iron ore pellet
producing industry
* Steel industry would see a 9.5 percent increase in
electricity rates reflected as a cost increase of $l/ton of
steel shipped,
* Increased costs in cents per pound of non-ferrous metals
under full and partial scrubbing alternatives:
Full Partial
Aluminum
Copper
Lead
Zinc
2.2
0.4
0.06
0.49
DOE
1.2
' 0.19
0.05
0.28
UARG
1.0
0.16
0,036
0.19
In 1990, total increases in production costs of non-ferrous
metals under full scrubbing will be more than double the
increase under partial scrubbing, the amounts ranging from
about $1 million for lead to over $11 million for copper.
2-197
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2. D-321, D-369
Comment: The impact on the ESP industry in an estimated shift of
$500 million to the baghouse industry is regarded as
unfair.
3. D-215
Comment: The-increases in cost to local and state governments for
administration and enforcement are unwarranted*
4. D-276
Comment: Oppose the standard since it impacts the transportation
infrastructure and may impact the use of coal by Midwest
industries.
5. D-210
Comment; Oppose the standard due to excessive costs to smaller power
plants.
6. D-486
Comment: Reliability of pollution control equipment required by
regulation as proposed would be particularly expensive for
utilities with high load factors that provide little
opportunity for shifting. These costs would directly
affect major industries in the vicinity of this Upper
Midwest plant, especially iron mining and taconite pro-
cessing.
7. D-491
Comment: Full scrubbing will adversely affect the U.S. balance of
payments in foreign trade. Oil and gas imports required in
2-198
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1990 under it are projected by NERA to total $8.2 billion
compared to $4.4 and $6.0 billion under the UARG and DOE
proposals, respectively.
8.- D-421, D-508, D-643, P-lu
Comment: Marginal cost increases of the revised regulation are
unduly high under full scrubbing. These are the cost
increases in new facilities alone and represent 7.48
percent under the UARG proposal, 10.56 under the DOE
proposal, and 15.08 percent under full scrubbing.
Commonly, large industrial users of electricity are sold
Incremental electricity only at marginal cost. Therefore,
the inflationary effect of the proposed revisions on
energy-intensive industries will be far greater than
Indicated by consideration of average cost increases. The
results will operate inequitably on a regional basis. Full
scrubbing has a much greater potential than the sliding
scale for disrupting regional etnploynent. Western paper
industries would be at an economic disadvantage under the
proposed S02 standard. Specifically, under -full
scrubbing the increase for the upper midwest would be L3.32
percent as against 10.52 percent for the rest of the
nation, whereas under the DOE proposal the difference is
only 5.99 vs 5.98 percent.
2-199
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9. D-491
Comment: The cost to Industry will be felt In decreased coal produc-
tion and employment in the Appalachian coal fields, which
the Clean Air Act Amendments were designed to assist. Com-
pared to the UA1G sliding scale proposal, as projected by
National Economic Research Associates, Inc. full scrubbing
will result in Appalachian coal production in 1990 that is
12 million tons less and in employment of 6,000 fewer
miners.
10. D-628
Comment: Section 31L of the CAA Amendments calls for a study of the
effects of NSPS on the job market. Shifts in job
availability under the alternatives considered should be
examined regionally and subregionally for the mining indus-
try and for other industries that shift production due to
electricity costs. These data should be part of the record
before a final decision is made In revising NSPS and the
data should particularly Include the new options reported
for the first time in the Federal Register In December.
11. D-516
Comment: Economic Impact for Midwest Continent Power Pool:
* 13 percent Increase under full scrubbing In rate of paper and
allied products Industry versus 6 percent Increase if DOE
plan adopted*
* Paper Industry major growth industry for northern Minnesota
and Wisconsin
2-200
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* Economic impact will be especially felt by rural coops and
small municipalities where major growth is occurring, e.g.
$39-137/year in 1977 dollars of additional increases.
12. D-290
Comment: Regional industries will be aided by requiring the same
control requirements on all coal, regardless of sulfur
content.
2-201
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Measures of Economic Impact
1. D-611
Comment: Planned utility capital investment is a misleading measure
of the economic impacts of proposed revisions to NSPS. Be-
cause replacement of obsolescent plants will be more costly
under the revision than under continuation of the present
standards, fewer replacements will be made. Thereforej
less capital expenditure will be reflected and the economic
impacts are misleading.
The cost of the proposed revisions will grow over time
because the affected generating capacity will increase*
IPA's use of 1990 present value costs (43 FR 42164) fails
to take into account increases beyond that date and under-
states the impacts of the proposed revisions.
2-202
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Great Lakes Transportation
1. D-673 D-214, D-2453 D-265, D-267, D-357, D-598, F-ld
Comment: Concerned that proposed SC>2 standard would curtail
shipment of western coal via the Great Lakes.
» 7th District of Wisconsin would suffer serious economic
decline
• Cost of transporting and handling western coal is borne
directly by consumer through fuel adjustment clauses while
pass through of scrubber costs are subject to rate increase
hearings
• Buffalo Terminal to handle 14 million tons of coal/year.
Cost $50 - $150 million, $1 million already spent on design
» Use of local or regional coal is critical to -economic
well-being of many areas
* Great Lakes transportation is very economical
• Use of western coal would increase construction of Great
Lakes port facilities
2-203
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2.8 Environmental Impacts
General Comments on Environmental Impacts
1. D-28
Comment; More study is needed of the environmental impact of coal
cleaning.
2. D-245
Comment: Concerned over impact of creating coal boomtowns.
3. D-335
Comment: See no need to scrub in the middle of Iowa where record
crops are reported.
4. D-152, D-432, D-434, D-462, D-631, D-657
Comment: There is a need to minimize the various harmful effects of
pollution:
• on crops, livestock, property and human health
» significant deterioration of pine trees and lichen on Montana
ranch adjacent to Co Is trip
* long range impacts of sulfur rain, sulfate transport, etc.
5. D-599
Comment; Full scrubbing will have net adverse environmental effects:
* discourages investments in front-end cleaning technology
* increases scrubber sludge waste
* increases water consumption
• removes economic advantage of low sulfur coals which emit
less pollutants.
2-204
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6. D-611
Comment: The incremental reduction in S(>2 emissions over that
achieved under continuation of the current NSPS is somewhat
greater as calculated by National Economic Research As-
sociates, Inc. for the proposals advanced by EPA? UARG and
DOE than the model estimates reported by EPA in the Federal
Register for September 1978, The differences result from
estimates that lower sulfur coals will be burned because
the cheaper control costs associated with them will more
than offset their higher purchase price.
Regional impacts in S02 emissions as calculated by
National Economic Research Associates, Inc. show that under
the proposed revisions to NSPS those areas with the highest
emissions (Middle Atlantic and East North Central) are not
the ones where the greatest reductions will be achieved.
Emissions in the Middle Atlantic region are calculated to
increase under full scrubbing while declining under the
sliding scale projected by DOE and UARG.
7. D-627
Comment: The proposed NSPS with full scrubbing will not result in a
reduction of S(>2 emissions or of ambient concentrations
for new power plants. Instead} when low sulfur coal is
used;, the new plants will simply be much larger, up to the
maximum size determined by the combination of the revised
2-205
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NSPS and limitations imposed by PSD Class II Standards for
new sources.
8. D-625
Comment: The SC>2 emissions will be greater than those projected by
EPA under full scrubbing. Technology will not be able to
achieve the 100 percent compliance assumed by the predic-
tive model,
9. D-631
Comment: The Clean Air Act requires IPA to favor health and en-
vironmental protection in resolving uncertainties in the
evidence of adverse effects. Adverse environmental effects
must be minimized even if technology is forced and control
costs are not "grossly disproportionate."
10. D-491, F-ly
Comment: Full scrubbing would require much more lime scrubbing, as
distinguished from limestone scrubbing;, than the UARG
proposal. The increase in lime production would result in
increased air and water pollution and solid waste storage
problems at the lime production facilities.
11. D-592
Comment: Articles and studies are submitted in support of full
scrubbing addressing:
• the role of S02 in obscuring visibility
• formation of harmful sulfates when SC>2 and particulate
matter interact
2-206
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* harmful effects reported from N(>2
12, D-598
Comment: The effect of a sliding scale is seen as reducing the net
emissions of pollutants in the Great Lake states.
2-207
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Sludge
1. D-175, D-210, D-223, D-224, D-227, D-231, D-Z34, D-250, D-252,
0-254, D-274, D-300, D-314, D-322, D-332, D-347, D-361, D-367, D-373,
0-446, D-458, D-459, D-467, D-469, D-473, D-491, D-523, D-657, D-735
Comment: Adverse effects of sludge disposal were not adequately
assessed and/or the costs were underestimated.
* Handling of solid waste from small units particularly
burdensome
* Cost of sludge disposal
* Sludge disposal leaching
* Full scrubbing produces 50 percent more sludge than DOE
proposal
* Excessive land areas will be required for sludge disposal
• Availability of sludge disposal sites may be severely limited
under other legislation such as the Surface Mining Control
and Reclamation Act of 1977 and the Farmland Preservation Act
of Wisconsin. Impact of farmland loss in Wisconsin may be
greater 'than that of allowing an incremental increase in
SC>2 emissions.
2. D-419
Comment: Scrubbing anthracite coal would produce only 30 Ibs of
sludge per MW hour compared to 130 lba/M¥ hour for 3.5
percent S bituminous coal.
3. F-lt
Comment: The land required for sludge and ash disposal under the
proposal will amount to only about 1 percent of utility
requirements for land use compared with over 90 percent for
transmission lines, coal mining and transportation.
2-208
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4. D-631
Comment: The adverse environmental effects of sludge have been
grossly exaggerated. The benefits of scrubbing far
outweigh the detriments of sludge disposal,
5. D-491
Comment: Pull scrubbing will severely impact the problem of solid
waste disposal. An estimate by National Economic Research
Associates, Inc. projects the increase in scrubber sludge
under full scrubbing to be 12.86 million tons - more than 6
times the increase under partial scrubbing. The sliding
scale is estimated by the same projection to decrease the
amount of ash requiring disposal^ whereas full scrubbing
will increase it. Based on disposal costs of $20 per ton,
partial scrubbing will reduce expenses for waste disposal
from $155 to §95 million whereas full scrubbing will
increase it by $49 million.
2-209
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Acid Rain
1. D-98, D-107, D-169, D-2303 D-260, D-359, D-367, D-493, D-501,
D-507, D-6315 D-5923 D-666, D-668
Comment; Concerned about acid rain if S(>2 standard is not strict.
2-210
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Ambient Air Quality
1. D-I66, D-230, D-267, D-271, D-294, D-331, D-370
Comment: Coacerned about degradation of ambient air quality.
2. D-5, D-132, D-347.
Comment: Cite British position that some S02 is beneficial to
agriculture.
3. D-458.
Comment: Maryland is considering relaxing the SIP for plants from
0.03 lb/10^ Btu to current NSPS level due to the minimal
air quality impact.
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Prevention of Significant Deterioration (PSD) Program
1. D-130
Comment: Partial scrubbing would undermine the PSD clause in the
Clean Air Act.
2. D-330, D-368, D-371, D-373, D-417, D-467
Comment: PSD should not be considered in developing the NSPS since
the PSD increments are a matter for state and local
agencies.
3. D-120, D-223, D-280, D-32Q, D-367, D-391, D-403, D-404, D-416,
D-421
Comment: PSD should be considered in action.
4. D-2&2, D-414
Comment: PSD provides a mechanism for improving air quality and
should be considered on a case-by-case basis .as an
alternative to full scrubbing,
5. D-320, D-410, D-433, F-ly
Comment: PSD is already too strict. It would be discriminatory to
require more scrubbing than the PSD would require^-*? ~
6. D-4723 D-490, D-498, D-516
Comment: PSD provisions should provide sufficient environmental
protection. The proposed standard would inhibit
technological innovation and preempts the states from
exercising authority granted in Clean Air Act to achieve
2-212
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optimum balance of competing factors in the design of state
strategies.
7. D-482
Comment: During the three-day exemption from full scrubbing (75
percent), will the unit also be exempt from PSD?
8. D-435
Comment: PSD increments would be used up more quickly under proposed
standard.
9. D-518
Comment: Worried about "grandfathering" plants. PSD regulations
will come under pressure as growth takes place,
10. D-631
Comment: The NSPS must assist the PSD program by insuring that tight
standards minimize threats to visibility.
11. D-501
Comment: In. one county, Detroit Edison is taking 80 percent of the
PSD increment.
12. F-ls
Comment: It is not necessary for NSPS to require maximum possible
controls in order to prevent significant deterioration so
as to meet the requirements for non-attainment areas: this
is a separate consideration.
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Water
1. D-263, D-265, D-2.71, D-320, D-321, D-410, F-ls
Comment: Concerned about water use
• Question wet vs. dry scrubbing in areas of scarce water
supply
• Estimate 15 percent increase in scarce water usage.
2. D-491
Comment: Analysis of the feasibility and cost of treating potential
waste streams by EPA and its contractors is totally
inadequate. Specific examples from the EPA/Radian report
are cited.
3. F-ly
Comment: In arid regions of the west3 requirements for water by
utilities already burning low sulfur coal will waste water
in reducing emissions below the level needed to assure
health and welfare of the population.
2-214
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Other Legislation
1. D-270, F-lu
Comments The proposed standard restricts SIP planning "by setting
permissible levels at the edge of available technology so
that state initiative in providing the degree of stringency
required by local conditions is preempted.
2. D-474
Comment! Surface Mining Reclamation Act was intended to make surface
mining environmentally acceptable. Interacts with analyses
since costs will be higher in the westt Also, the
objective of reducing reliance on western coal Is in
conflict with objective of Mining Act which was to minimize
the adverse effects of surface mining to permit greater
utilization of the resource*
3, D-266, D-3L4, D-469, B-473, D-491
Comment: The effects of KCRA on sludge disposal cost were not taken
into consideration.
4. D-290
Comment: Strict standards would be an aid to preventing
deterioration of air standards (under other sections of the
Clean Air Act amendments) and thereby would enable us to
attract industry and promote county growth. A strict NSPS
will save costs to local and state governments by reducing
2-215
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litigation when permits are sought under other provisions
of the Clean Air Act.
5. D-491
Comment: Concerned about cost of sludge disposal in light of the
Clean Water Act.
6. D-627
Comment: The NOX standard can, with difficulty, be met for new
boilers but is unlikely to be achieved in retrofit of
existing boilers. Therefore, care should be taken to avoid
any tendency to force the SIPs to reduce their requirements
to similar levels.
7. D-519
Comment: The analyses fail to address the impacts of RCRA3 TSCA3
FWPCA.
2-216
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2.9 Energy Impacts
1. D-39, D-167, D-242, F-lu, D-599
Comment: General comments on increased energy required to meet Che
standard.
2. D-287
Comment: The proposed standard undermines any chance to develop
Intermountain Area electric power (which appears to depend
on use of local Western coal).
3, D-132, D-347
Comment: Baghouses for control-of particulate emissions would re-
quire significant additional energy to operate due to
increased draft losses.
4. D-156, D-167, D-223, D-224, D-227, D-246f B-262, D-300, D-15,
F-ly
Comment: Flue gas desulfurization energy requirements:
* increase NOX, SC>2, and CO
• exact a 5 percent energy penalty
* encourage use of oil under full scrubbing
5. D-245, D-246
Comment: The proposed regulations will expand the available energy
by allowing the use of high sulfur coal,
6. D-42, D-410, D-683
Comment: The energy penalty and costs of FGD are too high relative
to the potential air quality improvement. The optimum
2-217
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level (in terms of health and welfare) has not been es-
tablished. The standard should be withdrawn until such
time as it is.
7. D-422
Comment: The standard encourages use of gas and oil instead of de-
veloping coal reserves.
8. D-491
Comment: While under all alternatives considered, the total coal
production in 1990 will be less than under continuation of
present NSPS as estimated by National Economic Research As-
sociates, Inc., the relative decline will be about 5 times
greater under full scrubbing than under the sliding scale
proposed by UARG (144.8 million tons compared to 27.8 mil-
lion). The effects will be felt in the Appalachian coal
fields which the Clean Air Act amendments were intended to
assisti As estimated by NERA, the 1990 difference in pro-
duction of Appalachian coal between full scrubbing and the
continuation of current NSPS may be nearly 3 times the dif-
ference reflected under sliding scale - 19.1 million tons
vis-a-vis 6.7 million.
9. D-611
Comment: The estimates of incremental oil and gas consumption over
that projected under continuation of current standards are
far higher as calculated by National Economic Research
2-218
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Associates, Inc. than in the estimates reported by EPA in
the Federal Register Eor September 1978, NE1A estimates of
the incremental consumption are more than double those re-
ported ag projected under full scrubbing. Incremental
increases under partial scrubbing are also higher than re-
ported by EPA, but by lesser amounts.
10. b-491
Comment: The EPA S02 proposal has a greater adverse energy impact
than the UARG or DOE alternatives because
• it would discourage the phase out of existing oil and gas
facilities
o it will cause a significantly greater increase in oil demand
than will the sliding scale alternative
* it would discourage strengthening of west to east transporta-
tion facilities, thus lessening the availability of low sul-
fur coal for non-utility use.
11. D-642
Comment: Full scrubbing as proposed would preclude the use of high
sulfur Appalachian and tnidwestern coals that could be
burned under the UARG proposal. The latter allows a. ceil-
ing of 1.5 lb/10" Btu of S02 with appropriate percent-
age reduction.
12. F-lu
Comment: Full scrubbing does not permit utilities burning low sulfur
coal to use reheat for bypass and consequently increases
the energy penalty over that associated with DOE and UARG
pr op o s a 1 s.
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2.10 Health Effects
1. D-230, D-359, D-360, D-363, D-439, D-494
Comment: Partial scrubbing will cause increase in sulfates or trace
elements. Therefore, S02 standards should be strict.
Lane and Saskin (Air Pollution and Human Health) are quoted
that reducing- participates and S02 would lower mortality
4.7 percent.
2. D-38, D-113, D-114, D-167, F-lz
Comment: The standards are misdirected or not needed.
* Three articles are submitted indicating S02 is not
harmful.
* The position taken is that EPA is bombarding the public with
totally erroneous claims of human health damage that are
scientifically unsupportable. National resources are being
wasted.
• Standards focus on short-term pollution exposure while scien-
tific evidence shows that as much as 95 percent of all damage
is from long-term exposure.
» Health effects are not an issue in Iowa. Rural America
should not suffer for metropolitan problems.
3. D-631
Comment: The Clean Air Act requires EFA to favor health and environ-
mental protection in resolving uncertainties in the evi-
dence of adverse effects. Adverse health effects are well
documented in reports such as:
• the Rail Report
• the NRDC Report on Health Effects of Fine Particulates
» Lane and Saskin - Health Effects of Sulfates and
Particulates - The Estimated Economic Value of These Effects
2-220
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* 1975 NAS Study - Money Value of Sulfur Emission Damages
Thus, the standard must be made very strict even if tech-
nology is forced and costs are not "grossly dispropor-
tionate."
4. D-592
Comment: Article submitted in support of full scrubbing discusses
evidence for an association of adverse effects on human
health and air pollution including sulfates (from SOX and
particulates) and NOX. Some studies established signifi-
cant correlation between specific adverse health, effects
and ambient concentration whereas others have not. It has
been difficult to estimate the continuing effects of other
factors to establish threshold levels; and to determine the
impacts for different groups of the population, fables are
offered relating specific expected adverse health effects
to quantitatively expressed pollutant concentrations in the
atmosphere.
5. F-lu
Comment; Adverse health effects can result from the high cost of
electricity such as the inability to provide adequate air-
conditioning in nursing homes during heatwaves where deaths
have been attributed to the lack of proper air condition-
ing.
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2.11 General Comments on Entire Standard
1. D-4, D-29, D-45, D-53, D-55, D-58, D-59, D-68, D-92, D-96, D-109,
D-lll, D-127, D-138, D-159, D-160, D-164, D-165, D-171, D-193, D-222,
D-228, D-241, D-248, D-258, D-269, D-291, D-292, D-295, D-296, D-216,
D-318, D-353, D-358, D-376, D-383, D-740
Comment: Support the proposed standard with no specific reasons
given.
2. D-43Q
Comment: The use of additives as supplemental abatement techniques
was not addressed; these are opposed and should not be
part of BACT but concern is expressed that they may be
forced on plant operators to meet the standards promul-
gated:
* use of sulfur compounds to improve ESP performance is
counter productive
* use of sodium compounds for the same purpose is suspect
because of potentially adverse effects on both equip-
ment and character of emissions
• use of ammonia to improve rate of NOx emissions is far
from state-of-the art and may lead to significant
ammonia releases,
3. D-447
Comment: EPA, in the support documents, did not treat the impacts
of cycling type plants on the data used to support its
proposal. Most new plants brought on line by the utility
community will be cycling type.
2-222
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4. D-215
Comment: The entire proposed standard has gone beyond Congressional
Intent.
5. D-114
Comment: Favor the high stack approach. Dispersion methods exist
for lowering health, hazard at less cost.
6. D-114
Comment; The entire regulation encourages prolonging the life of
inefficient old plants.
7= D-113
Comment: A multi-strategy approach should be used for pollution
control with less strict limits on each component of the
approach,
8. D-225
Comment: The use of biomass fuel in a direct fired industrial
combustion boiler may have some ramifications involving
NSPS. Ho examples given.
9. D-302
Comment: EPA should not be allowed to tell industry what methods
must be used to reduce emissions. 'This discriminates
against free enterprise. Emission limits should be set
and industry should be free to meet them any way it
chooses.
2-223
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10. D-454, D-572
Comment: Against the EPA proposed standard as inflationary to the
^manufacturing industry and in general.
11. D-631
Comment: The standard must be technology-forcing. Thus, the "best
system of continuous emission reduction" must go beyond
what is routinely available on commercial units. The
proposed standard does not do this.
12. D-631
Comment: The dominant part of IPA's analysis during the selection
of the "best system of continuous emission reduction" must
be the determination of the performance of the best tech-
nology. Several court decisions make clear that economic
considerations are entitled to only very limited weight.
If EPA declines to require the use of some available con-
trol devices, the Agency must show clearly that their
costs are "grossly disproportionate" to the health and
environmental benefits they would provide. Both the EPA
and DOE proposals emphasize the cost factors too strongly.
13. D-631
Comment: Section 111 requires each NSPS to control all significant
pollutants from a source category. This standard must
therefore adequately limit emissions of polycyclic organic
matter (POM), trace metals, and radionuclides, which may
pose significant health hazards.
2-224
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14. D-631
Comment: The percentage reduction and the ceiling must indepen-
dently be instruments of emission reduction, technology-
forcing and growth promoting. EPA has proposed a minimum
percentage reduction coupled with a. ceiling that never
requires reduction beyond the minimum percentage. In con-
trast, DOE would have EPA select a ceiling and then choose
a percentage reduction that never achieves emissions lower
than the ceiling. Both approaches would make one or the
other part of the composite standard meaningless. This is
not the intent of Congress.
15= D-491
Comment: EPA failed to recognize material differences among power
plants as allowed by the Clean Air Act, as follows:
e Section lll(b)(2) of the Act says the Administrator
"may distinguish among classes, types and sizes within
categories of new sources" for the purpose of estab-
lishing standards (emphasis added).
e Section lll(b) of the Act, prior to the 1977 amend-
ments, also allowed EPA to establish different stan-
dards for different classes or types of facilities
* the 1977 amendments did not affect the ability to sub-
categorize various classes, types and sizes of utili-
ties.
16. D-491
Comment: In developing the standard EPA did not strike the proper
balance among emissions reductions, costs, energy impacts,
and non-air health and environmental impacts.
2-225
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17. D-491, F-lu
Comment: Under the terms of Section 113 of the Clean Air Act, the
revised NSPS will have the force of a substantive criminal
statute defining feloneous conduct. Under "due process of
lav" concepts the emission limitation, the percentage
reduction requirement and the means for compliance deter-
mination must be unambiguous and achievable* EPA's fail-
ure to adhere to this principle might well render the
standard unconstitutional.
18. D-491
Comment: Section lll(a)(l) of the Clean Mr Act requires that each
new eource performance standard be "achievable." This, in
turn, hinges on whether the entire system in question has
been adequately demonstrated. Adequate demonstration
applies both to the emission control system and the com-
pliance determination system (i.e., compliance testing and
continuous monitoring). The supporting material to the
proposed NSPS does not adequately demonstrate that either
emission control systems or compliance determination sys-
tems are state-of-the-art for Long term day-to-day opera-
tion on large utilities. Thus, the proposed standard is
illegal under section lll(aMl) of the Act.
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19. D-515
Comment: Against the location of any coal-fired plant in the San
Joaquin Valley.
20. D-519
Comment: Numerous conflicts are present between the various con-
tractor reports on technical issues. These conflicts
indicate a weak data base and poor evidence for setting
the standards (Explicit comparisons are given in
comment)*
21. D-629, D-634
Comment: Finds no substantive environmental gains or differences
among any of alternatives analyzed and therefore recom-
mends adopting DOE proposal on economic grounds. Wishes,
however, that the option selected should protect mid-
western coal production.
22. D-702, D-716, D-726, D-727
Comment; Requests that the proposed standards be given a thorough
risk analysis and economic evaluation.
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2.12 Comments Not Addressing the Proposed Standard
D-15, B-38, D-43, D-65, D-117, D-157, D-203, D-230, D-328, D-338,
D-408, B-484, D-529, D-534, B-536, D-581, D-586, D-594, D-603, D-604,
D-636, D-638, D-656, D-661, D-664, D-&65, D-671, D-707, D-743
2-228
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2.13 Comments Duplicating Previous Submissions
D-5273 D-528, D-530, D-535, D-543, D-544, D-550, D-553, D-555, D-560,
D-557, D-559, D-563, D-596, D-580, D-589, D-591, B-597, D-615, D-617,
D-618, D-619, D-649, D-650, D-652, D-654, D-655, D-658, D-662, D-669,
D-672S D-676, D-677, D-679, D-680, D-681, D-685, D-686, D-687, D-689,
D-690, D-699, D-700, D-727, D-732, D-742, D-745, D-746, D-752, D-754,
H-9.
These conunents fall into one of two categories:
o A duplicate of a previous submission usually transmitted
through an alternate channel such as a Senator, Represen-
tative or the President's office.
o A defacto duplicate containing minor corrections or clarifi-
cations. Any resubraission containing major substantive new
material was treated as a separate comment and is not re-
corded here.
2-229
-------
A
-------
3. SULFUR DIOXIDE
3.1 INTRODUCTION
On September 19, 1978, EPA proposed standards for control of sulfur
dioxide emissions from power plants. Although a uniform $02 control
requirement was proposed, the Administrator specifically noted that
no final decision had been reached and that a number of alternatives
were being considered. A summary of impacts for the alternatives under
consideration at that time was presented in the preamble to the proposal
(43 FR 42165) and in the Supplement to the document "Electric Utility
Steam Generating Units, Background Information for Proposed S02 Emission
Standards" (EPA-450/2-78-00?a-l), On December 8, 1978, EPA provided
analyses of additional alternatives under consideration (43 FR 57834).
Further analyses of the most recent alternatives considered are contained
within the preamble to the promulgated regulations and in the docket.
Since proposal, additional technical data describing flue gas
desulfurization system performance has been collected. EPA has collected
information on the performance of dry control systems and has placed this
material in the docket. A summary of dry control system performance is
given in the preamble to the final regulations. A more detailed
report on the performance of dry control systems and their economic,
environmental, and energy impacts is given in section 3.4 of this
document.
3-1
-------
Additional data on the performance of wet scrubber sulfur dioxide
control systems has also been collected. These tests followed the
initial data collection effort contained in the EMB Report 77 SPP 23A
(August 1978} that were described in the Background Information Document
for proposal (EPA-45Q/2-78-Q07a-l). The results of these FGD performance
tests are presented in two test reports.
- Test report A contains the results of monitoring the performance
of FGD systems at (1) the Columbus and Southern Ohio Electric Company's
Conesville Station, (2) the Tennessee Valley Authority's (TVA) Shawnee
Station, and (3) the Northern Indiana Public Service Company's (NIPSCO)
Mitchell Station. Test Report B contains the results of monitoring
units at Kansas Power and Light Company's Lawrence Station and additional
tests at TVA's Shawnee Power Station. Testing was also attempted at
Kansas City Power and Light Company's LaCygne Station, but testing was
not feasible due to boiler outages.
3.2 PERFORMANCE TEST REPORT A
This test report includes results of monitoring the following FGD
systems:
1. At the Conesville No. 5 plant of Columbus and Southern Ohio
Electric Company, EPA gathered continuous SO, data for the period from
July to December 1978. During the test period, data for only 34 days
were gathered due to frequent boiler and scrubber outages. The Conesville
system averaged 88.8 percent SOp removal. Outlet SO- emissions averaged
0.80 Ib/nrillion Btu.
2. The performance of the Wellman-Lord FGD unit at NIPSCO's
Mitchell station was monitored during 1978, including 1 41-day continuous
period of operation. Data from this period were combined with previous
data and analyzed; averaging 0.61 Ib/SO^/million Btu and 89.2 percent SO,
removal for the 56-day test period.
A
-------
3. From December 1978 to February 1979, EPA gathered continuous
SOg data from the 10 MW prototype unit at TVA's Shawnee station using
a TCA absorber with lime. Forty-two 24-hour periods of data were obtained
when 3.0 percent sulfur coal, was fired, SCL removal averaged 88.6 percent,
•Due to the intermittant operation of the Conesville unit which had
started up in'June shortly before EPA began monitoring performance and
which was undergoing shakedown of the equipment, much of the data were
collected during periods when the operation had not completely stabilized.
For this reason9 the variability of data for this unit was higher when
compared to the data for the other two units tested at NIPSCO and TVA's
Power Stations.
At the Conesville and TVA installations, SOo and 0? concentrations were
measured upstream and downstream of the FGD system using continuous
instrumental monitors. Copies of boiler operation logs and FGD system
operation logs were obtained to document process operating conditions
during the monitoring periods. At the yeTlman-Lord demonstration site,
a wealth of information is being generated including C0~, CL, H-0, SO,,
and coal analyses. The mass emission data was submitted by the EPA
contractor based upon a combination of these data to produce the most
accurate results on a mass basis.
As in all cases, the instruments (except NIPSCO) used to generate
data have been subjected to the appropriate test procedures (Federal
Register, Vol. 40:194, October 6, 1975) to assure accuracy of all data
reported herein.
3-3
-------
3.2.1 Description of Test Sites
3.2.1.1 Conesyll-le Unit No. S.^Colunibus and Southern Ohio^Eljctric
Company
Conesville 6enerat1ng Unit 5 is a coal-fired unit rated at a
net capacity of 375 MW. The steam generator is a Combustion Engineering
controlled circulation, single reheat, balanced draft boiler with a
primary steam flow of 3,130,000 pounds per hour at 2620 psig, 1005°F,
The turbine generator is nominally rated at 403 MW. The fuel supply is
raw (unwashed) coal as delivered direct from the mine. Typical coal
analysis is 14.0 - 16.0 percent ash, 3.5 - 4.5 percent sulfur, with a
high heating value of 10,400 to 10,800 Btu/per pound.
The flue gas passes from the boiler to a cold side electrostatic
precipitator (Research-Cottrell, weighted-wire, 99.65 percent design
particulates removal), induced draft fans, and then to either the flue
gas desulfurization system or the full-flow bypass before final exhaust
through an 800 fot acid-resistant, brick-lined stack. See Figure 3-1.
3-4
-------
1
U1
o-
SERVICE
HATER
TO BT PASS
DUCT
LIHE
\7
HEIGHT FEEDER
SLAKING
ANO DILUTION
SCRUBBER
PRESATURATOR
dflKE UP
SLURRY TANK
RECYCLE TA«K
WASH TflHK1
HASTE
SLURRt
TANK
CLEAN GAS
RECLAIMED
HATER TANK
PONO
WASTE
DISPOSAL
SVSTfM
Columbus and Southern Ohio Electric, Conesville No. 5 FGO System:
Process Flow Diagram.
Figure 3-1
-------
The FSD system consists of two mobile-bed scrubber modules furnished
by the Mr Correction Division of Universal Oil Products. Each module is
designed to handle 60 percent of the total full-load flue gas flow (total
flow - 1,202,271 cfm at 286°F) with a minimum S02 removal efficiency of
89.6 percent. The flue gases are contacted countercurrently in a single
stage spherical-packing mobile bed with thiosorbic lime slurry. The scrubber
effluent slurry is. recycled with a bleed-off to a thickener. The thickener
concentrates the solids from 9 percent to approximately 30 percent solids.
The thickener underflow is pumped to a treatment plant for sludge fixation
and disposal. The thickener overflow is recycled to the scrubber presaturator
and lime slaker.
The Unit 5 scrubbers were placed in service 1n February 1977.
3.2.1.2 Shawnee FGD Prototype. Tennessee Valley Authority
The Shawnee Power Station, operated by the Tennessee Valley Authority
(TVA), is a coal-fired steam generation station having 10 turbines, each
-served by a boiler and stack, A portion of the exhaust gases from one of
these stacks is directed for use with three pilot plant scale wet scrubbers
systems - a venturi with a spray tower after absorber, a turbulent contact
absorber (TCA), and a-marble bed absorber. Testing was performed on the
ventyri/spray tower using limestone enhanced with adipic acid and the TCA
using Hme only. This report describes the test and results for the
TCA/lime system.
The venturi system was manufactured by Chemical Construction Company
in the late 1960's and contains an adjustable throat which permits control
3-6
-------
and variation of pressure drop. The TCA unit, constructed by Universal Oil
Products, uses a fluid bed of low density plactic spheres that"migrate
between retaining grids. The marble-bed absorber is -no longer operated.
Figure 1-2 is the process flow diagram for the Shawnee TCA/lime system.
3.2.1.3 Mrtchell No. 11, Northern Indiana PuTb.1iiTC__Service Company .
The D.H. Mitchell Mo. 11 boiler is a balanced draft, wet- bottom radiant
wall-fired reheat boiler manufactured by Babcock and Wilcox. The maximum
rated output is 115 meqawatts. Service began in 1969. Detailed boiler
characterization may be found in EPA 600/7-77-014, dated February 1977.
The Wellman-Lord FRD system (Figure 3-3) consists of three major
operating sections - SOg absorption, purge treatment and SOg regeneration. In
the SOp absorption sectum, residual fly ash in the flue gas is removed by
a wet scrubber. SCL is then removed by scrubbing with a sodium sulfite
solution. The scrubber purge helps maintain inactive sulfates and their sulfates
at tolerable levels in the sodium solution.
The absorbed SO- is thermally regenerated to release SO- as a concentrated
qas stream and enable the reconstituted scrubbing solution to be recycled to
the absorber. The concentrated SCU is converted to elemental sulfur at Mitchell
No. 11 as shown in Figure 3-3 by the Allied SOg reduction process using natural
gas and a Claus sulfur recovery system. Glaus tail qas is incinerated and
recycled to the flue gas upstream of the absorber.
3-7
-------
I AIR
[FUEL OIL
REHEATER --
i
1-
SCRUBBEfiVt-Jt
-------
DISCHARGE
TO STACK
CONDENSER
PRESCRUBBER
(VARIABLE-THROAT
VENTURI)
v£>
FLUE GAS FROM
UNIT
FLY ASH PURGE TO POND
TRAY TOWER
ABSORBER
TREATED
PURGE STREAM
SODIUM SULFATE
CAKE
EVAPORATOR/
^CRYSTALLIZER
COMPRESSOR
DRIED
SULFATE
PRODUCT
Northern Indiana Public Service,
D. H. Mitchell No. 11 WeiIman, Lord/Allied System:
General Process Diagram,
Figure 3-3
-------
3.2.2 Dat_a_ Gathering Systems
The sulfur dioxide monitoring equipment at all test locations were DuPont
460 Photometric Analyzers. The basic instrument configuration varied from site
to site and 1s discussed in the following narrative. Typical sampling locations
are shown in Figure 3-4 for. a two module FGD system.
Oxygen monitoring equipment varied from site to site; however, the basic
detection principle was the same. The oxygen measurement equipment is also
described in detail below. Continuous instrumental moisture measurements were
not performed. The moisture contents of the sample streams were determined by
manual procedures. The test procedures used at each location are described as
follows:
3.2.2.1 Conesyi'Tle No. 5, Columbus and Southern Ohio Electric Company
Figure ^3-5 illustrates the DuPont 460 S07 analyzer and Thermox HOG III
oxyoen analyzer scheme used at Conesville No. 5. The gas sample was extracted"
from the stack through a 30 micron metal filter element and a heat traced teflon
sample line. The sample probes were equipped with electrically operated three-
way values for automatic high oressure air back purge of the filter element, and
for remote injection of calibration gas to the sample line/analyzer system.
Oxygen was determined with a Thermox WDS III zirconium oxide-cell analyzer.
The sample for oxygen analysis was withdrawn from the SCL analyzer, so that
SO, and (k were measured in the same gas stream. The operating cycle of the
analyzer was 10 minutes. During this period there were approximately
Mention of a specific company or product name does not constitute endorsement
by the Environmental Protection Agency.
3-10
-------
MOGULS A
INLET PROBE A
OUTLET PROBE A
OUTLET PR08£ B
SAMPLE
LINES
amss
DUCT
. OUTLET AHALKERS
LT
1
_J
1
INLET .
ANALYZERS
HOtNJLE E
TO
STACK
SAMPLE AND
CALIBRATION
LINES
INLET PROBE 3
IKLET
CALIBRATION
TASKS
i
1 1
I I
TRAILER
T"
SCRUBBER
CONTROL
ROOH
OUTLET
CALIBRATIOt
/ TANKS
Figure 3-4. Typical Scurbber Sampling Locations
3-11
-------
**fu
maun
Figure 3-5. Instrument System Schematic-ConesvlUe No. 5
3-12
-------
4 1/2 minutes of sample analysis and 1/2 minute of automatic zero and
probe backflush for each of the two sample points. The SCU analyzer output
was recorded on a two pen recorder, and the 0- analyzer output was recorded
on a single pen. recorder.
The outlet analyzer system was identical except that the measurement
range for SCU was 0-1000 ppm.
Moisture data were collected using manual procedures. At approximately
weekly intervals, samples were collected usinq either drying tubes or condenser
techniques at the inlet and outlet ducts, and also after the condensate
separator is the SO, analyzer. The sample stream temperature at each con-
densate separator was recorded daily. The sample stream moisture contents
were assumed (and confirmed by manual tests) to be saturated at the average
condensate trap temperatures for generally, a week-long inteval.
Copies of the daily FGO system operator's log were collected along with
daily instrument logs and instrument operation and calibration data sheets.
3.2.2.2 Shawnee 10A and 10B, Tennessee Valley Authority.
A schematic diagram of the monitoring system used at each of the four
monitoring locations is shown in Figure 3-6. The sulfur dioxide (SOn)
instrument at each location is a OuPont 460 analyzer. The oxygen (Q-) analyzer
is a Thermo* model WDG 3 instrument. The ranges of the scrubber inlet SO-,
analyzers are set at 0-4000 ppm S0? and the ranges of the two scrubber outlet
SOn analyzers are 0-1000 ppm. The ranges of 0, analyzer are all set at
0-10 percent Op. The S02 and 0, probes tips are located at the stack centers
with the 07 probe approximately 1 stack diameter upstream of the SOp probe at
3-13
-------
I
*»
S0? Probe
Heated Teflon line
Calibration gas
valve
Recorder
Figure 3-6. Instrument System Schematic, Shawnee Power Station.
-------
each of four locations. The analyzers operate on approximately 8-minute
cycles durina which stack aas concentration measurements are made continuously
except for an automatic 1-minute backflush period. Concentration measurements
are recorded continuously on four strip chart recorders located in the scrubber
control room.
The moisture content correction for the SQ«'gas measurements was determined
from the temperature measurement in the sample gas stream immediately following
the knock-out trap in the analyzer case. This gas was assumed saturated at
this temperature. The moisture content correction for the 02 gas measurements
was the stack moisture content as the 0, analyzers measured a wet gas stream.
3.2.2.3 Mitchell. Mo. 11, Northern Indiana Public Service Company
(The information on the gas sampling and analysis procedures at Mitchell
No. 11 were not received in time to incorporate in this report and will be
added when the final report on SO 2 monitoring at power plants is issued by
EPA).
3.2.3 Data Reduction Procedures
The types of data that were collected for reduction purposes were:
inlet SO- strip chart (2 inlets)
inlet Op strio chart (2 inlets)
outlet S02 strip chart (2 outlets)
outlet 02 strip chart (2 outlets)
scrubber logs (including boiler load and coal feed rate)
instrument logs
instrument calibration data sheets
manual test results
3-15
-------
The data were first logged in as received and then were reviewed for
possible data gaps. The charts were then transcribed to a tabular format
using a strip chart data digitizer. The tabular data were then processed
through a manual keypunch operation so that appropriate scale factors, moisture
valuest process data, and descrlotive convents could be Included prior to data
listing. The punched cards were then processed by computer to obtain a data
listing and calculated results for each 15 minute data point. The data listings
were reviewed by the EPA contractor for keypunch or other transcription errors.
The scrubber and instrument logs were reviewed so that oerlods of boiler outage,
scrubber outage, bypass, startup or shutdown could be properly identified and
coded so that these data would not be Included in the calculation of averages
and sunnaries.
After data editing was completed, average sumnarles were prepared.
Averages based on the 15-nrInute data were prepared for consecutive 1-hour,
3-hour, 8-hour, and 24-hour intervals. In order to calculate an average
result for a single interval, it was specified that at least 75 percent of
the 15-minute data points be available for that interval. For example, an
8-hoyr average could only be calculated when 24 of the possible.32 15-ffiinute
data points were available. When less than 75 percent of the data were
available for an interval, an average was not calculated and blanks were
entered in the sunroary printouts.
After each 30 days of average interval data, a statistical summary
was prepared to determine the following parameters for the average.
3-16
-------
mean standard deviation
average deviation maximum
minimum range
percent standard deviation
These parameters were calculated assuming the data were normally distributed.
The calculation procedures used to convert the analyzer outputs for
sulfyr dioxide and oxygen concentrations to mass emission factors are given
in 40 CFR 60 Subpart D. This procedure is known as the F-factor approach and
is outlined below:
c _ CFK 20.9
l-M 20.9-02
1-M
Where E * Emission factor - Ib/million Btu
C = S07 concentration - ppmv, wet basis
F = Stoichiometric conversion factor, 9820 dscf/million Btu for
subbiluminous coal
_7
K = Conversion factor, 1.659 x 10 Ib/dscf per ppmv
02 = ' Oxygen concentration, percent by volume as measured
M = Moisture fraction as measured (for dried samples, M=0)
The sulfur dioxide and oxygen concentration results were obtained by multiplying
the strip chart readings as a percent of scale by the appropriate calibration
factor.
3-1?
-------
The emission factor was calculated for each FGD system inlet and outlet test
point. The sulfur dioxide removal efficiency for a module is calculated by:
Efficiency « Ein out x 100 percent
When more than one inlet and/or outlet test point was monitored, the total system
emission factors and sulfur dioxide removal efficiencies were calculated by a
weighted average orocedure. The equation for this calcualtion for total system
efficiency is given by:
EFF total « EFFA (FA) + EFFg(FB)
Where,
EFFf , = total system efficiency
EFF,, = efficiency of module or module set A
F,, = fraction of qas flow through module or module set A
= efficiency of module or module set B
Fg = fraction of gas flow through module or module set B
The only data for this report requiring the above approach was for
Conesville No, 5. Since modular flow was not equal, mass balance procedures
were developed to determine the gas flow rate through each module. The flow
rate exiting each scrubber module was measured by plant equipment and was
recorded on the scrubber logs. The bypass flow was estimated by calculating
the total gas flow to the FGD system based on stoichiometric relationships
3-18
-------
and subtracting the flow through the modules. The total inlet flow was
calculated based on scrubber outlet temperature, pressure and average moisture
content. Since the bypass flow estimate is the difference between two large
numbers, it is subject to significant error if any smaller errors are present
in the inlet or module outlet results. Therefore, the total system -performance
data should not be used as precise results, and are presented for estimation
purposes,
The equations used to calculate system performance, are as follows:
Total inlet flow rate (calculated at outlet conditions)
tf , « 1 Ts 29.92 20.9 HR
v
, _ _
t ye£:u T^io~ 530 Ps 20.9 - %02/(l-Mm) ~50~
Where Vfc - total volume flow in F6D system at outlet conditions (cftti, wet)
9820 =.stoichiometr1c combustion ratio, (scfm/10 Btu, dry)
Mo = FGO outlet moisture fraction
Ts = average outlet temperature (8F)
Ps = average outlet pressure (inches Hg)
202 - oxygen concentration measured at outlet (percent by volume)
Mm = analyzer moisture content, (volume fraction]
HR = heat input rate (10 Btu/hour)
Due to the flow meter calibration factors and the consistency of measurements,
the following assumptions can be made:
Ts = 12Q°F (annubar output basis)
Ps = 29.9 2"Hg(annubar output basis)
Mo - 0.115 (saturated at 120°F)
3-19
-------
The equation then simplifies to
v - 4229.8(Hr)
, OA Q ^H u nn j wet*
•£ £y ty *» &U«
1-Mm
The heat input rate is the coal feed rate (Ib/hr) which is recorded at
hourly intervals on the scrubber log sheets, multiolied by an average of
10,500 BTU/Tb (0.0105 x 106 Btu/lb)
The volume of flue gas bypassed is calculated by
VBP'Vt-VA-V8
Where
V«p = flow rate bypassed, cfm, wet, 120°F
VA = flow from module A, cfm, wet, 120°F
Vg = flow from module B, cfm, wet, 120°F
The system emission rate is calculated as a flow-weighted total by:
EBout)
vt
Where: -
E « system emission factor, lb/10 Btu
E« fc = module A outlet emission factor, lb/10 Btu
ES out • module B outlet emission factor, lb/10 Bty
E. . = module A inlet emission factor, lb/10 Btu
r\ 1 n
ED ,-„ = module B inlet emission factor, lb/10 Btu
dm
3-20
-------
The system 509 removal efficiency is:
r
:FF
EA in + EB in
(100)
3-21
-------
3.2.4 Data Analyses
3.2.4.1 Data Calculation Assumptions
In the orevious SOg monitoring report, several assumptions were made due
to direct oxygen or moisture readings being unavailable, which led to a
maximum error level due to the assumptions of 3 percent in emissions and
0.5 percent in percent removal efficiency,
For the data to be described, the only assumptions made were for moisture
on the NIPSCO Wellman-Lord 'system. For those data calculations moisture
contents were estimated from available charts of moisture versus boiler load.
No estimate of accuracy is readily available, however, the resulting error
is less than described above and based upon the expected accuracy of the
boiler charts used, error should be negligible.
3.2.4.2 Data Availability_
Table 3rl shows the data gathering breakdown for the three sites. The
total days sampling time was ascertained, then the boiler and scrubber down time
was subtracted to yield the net days available for scrubber performance data.
Data for each one-hour period was compiled and 24-hou'r periods characterized
as full data periods and partial data oeriods. "Full data" is defined as data
obtained when the boiler/scrubber system operated 18 hours or more and 18 hours
or more of monitor data was obtained within a calendar day. "Partial data" is
defined as data obtained when the boiler/scrubber operated less than 18 hr/day and
at least 75 percent of the monitor data was obtained during the operational period.
As shown in Table 3-1 the percentage data availability ranged from
33.3 percent total days at Conesville 8 module to 72.7 percent at Mitchell
No. 11 for overall efficiency, where both inlet and outlet data were available.
Partial days have not yet been analyzed at the Shawnee and Mitchell sites.
3-22
A
-------
TABLE 3-1. CATEGORIZATION OF DATA
Conesv1lie No. 5
Shawnee TCA
Mitchell No. 11
Total Days
Boiler Down
Scrubber Down
Net
l
Full Data Days
Partial Data Days
% Data Available:
Total Days
Partial Days
Module A
Module B
Inlet
184
22
-
162
105
5
64.8
67.9
Outlet
184
22
102
60
36
14
60.0
83.3
Both
Inlet &
Outlet
184
22
102
60
24
14
40.0
63.3
Inlet
184
22
-
162
94
5
S8.0
61.1
Outlet
T84
22
99
63
36
12
§7.1
76.2
Both
Inlet &
Outlet
184
22
99
63
21
15
33.3
57.1
Inlet
49
0
0
49
42
N/A
85.7
N/A
Outlet
49
0
0
49
42
N/A
85.7
N/A
Both
Inlet &
Outlet
49
0
0
49
42
H/A
85.7
N/A
Inlet
85
0
-
85
64
N/A
75.3
N/A
Outlet
85
0
0
77
64
N/A
72.7
N/A
Both
Inlet &
Outlet
85
0
0
77
64
N/A
72.7
N/A
-------
As in the first report, it _is important to note that the monitoring
systems.used were the existing systems and do not necessarily reflect state
of the art monitoring caoabiTitles. The simultaneous collection of Inlet and
outlet data as shown in Table 3-1 . are substantially less than expected for a
properly installed and operated new system, as reflected in a recent letter to
2
EPA from Texas Utilities. In that letter, one year's operation of a new
SOg/Og/HgO integrated system yielded 88 percent data availability with most
outages due to strip chart recorder malfunctions or unavailability of replacement
probes.
3.2.4.3 S _t at 1 s 11 c al An a T ys es
In the initial report and this report S02 monitoring data were analyzed
on the basis of 24-hour averages (Srhour and 8-hour averages were also
addressed in the initial report). Graphical analyses were made for inlet
SO-j, outlet SOo, and percent .SO- emitted (100 percent removal).
In this report percent SCu emitted (i.e., 100 percent SOp reduction) is
used to describe statistical performance of FSD units.
Figures 3-7, 3-8, and 3-9 graphically describe FGD performance at
Conesville No. 5. Figure 3-7 shows inlet SO, emissions average 7.50
lb/10 Btu with a geometric dispersion (GD) of 1.059. Figure 3-8 shows
outlet emissions averaging"0.80 lfa/106 Btu with a 6D of 1.802. Percent SO-
3-1
emitted in Figure 3-9 / averages 10.8 percent (89.2 percent recovery) with a
GD of 1.801.
Performance of the Shawnee TCA/lime system is reflected in Tables 3-10
through 3-T2. Inlet S02 in Table III-4 averaged 5.55 lb/106 Btu with a GD
2Letter, R. White, Texas Utilities, Generating Co. to C. Sedman, EPA, dated
January 16, 1979.
3-24
-------
of 1.116. Outlet SOp (Table 3-11) figures were 0.64 lb/106 Btu average,
1.279 GD. Percent S02 emitted on the TCA scrubber -(Table 3-12) averaged
11.4 percent (88.6 percent recovery) for 42 days with a GD of 1.204.
The WeiIman-Lord system statistics are represented by Figures 3-13
through 3-15. Actually the statistics here represent two .periods of
performance, approximately one year aparts which have been combined to
.represent a longer statistical period. Inlet SO, averaged 5.70 lb/10 Btu
3-25
-------
FROU«HI urr x i too CYCLES
KTuKIKt » L'^S^H CO N.I.L fc u , *
jc
HO
10
9
8
7
6
5
99.99 99 9 99.8
99 9S
9t> 90
80 70 60 bO 40 30 20
10
m
to
O
K^ 10.0
Figure 3-7 Conesville TCA/Llme
35 Days Inlet $02
1.0
0.01 0,05 0 1 0.2
99
90.8 99,9 99.99
-------
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10.0
a
7
e
5
4
3
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|_
CO
VO
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Cd ~£j-
CM
O *
1/1 s
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with the inlet SO, GO of 1,180 showing the effect of averaging coals from
two different lots. Outlet S02 averaged 0,61 lb/106 BTU (1.171 G5D)
(Figure 3-14 while percent SO- emitted averaged 10,8 percent {89.2 percent
recovery) with a GO of 1.131 (Figure 3-3.)
Table 3-2 lists the oertinent statistics from each test program.
Comparison of inlet variabilities shows the least variability with the
highest sulfur coal. This is perhaps due to the larger amounts of coal
used at Conesville per unit time which has the effect of blending when
compared to the smaller sources. In the initial report inlet S02 SO's
varied from 1.05 to 1.12, thus Conesville and Shawnee both fall within this
range. The SO of 1.180 at NIPSCO is substantially higher than the 1,12
originally reported for the. first 25 day period. As explained earlier, the
new GO is misleading because the two periods covered were over a year apart,
and two different coal lots are represented.
The outlet emissions and percentage reduction figures are all comparable.
Comparison to design figures is not directly possible except at Conesville
which has a minimum desigfi S0~ removal of 89.6 percent (long term). The 89.2
percent average figure reflects the intermittent operation effect upon scrubber
performance. The Shawnee TCA system was designed in the late 60's and design
data are not available. The Wellman-Lord system at NIPSCQ was designed at
90 percent SO, removal and 200 ppmv maximum outlet emissions. Conversation with
project engineers reveal that the 200 ppmv figure has not been exceeded (this
is the number used for control), but that due to lower sulfur coal being used,
the 90 percent removal is not being achieved, as is was for the higher sulfyr
coal used in 1977-1978.
3-35
-------
TABLE 3-2
FGO Performance Statistics (24 hour basis)
SOg Bate
Site/Scrubber Type
Cones »111e TCA/llroe
Shawnee TCA/Ume
NIPSCO Wellman-Lord
No. of
Periods
34
42
56
Inlet. !t»/10*BTU (GO)
7.50 (1,059)
§.§1 (1.116)
6.70 (1.180)
Outlet. 1b/10*BTU («)
0.80 (1.802)
0.64 (1.279)
0,61 (1.171)
Percent emitted (BO)
10.8(1.801)
11.4 (1.204)
10.8 (1.131)
-------
3.2.5 Conclusions
1. All three systems monitored show long term emissions control to
levels well below the 1971 NSPS of 1.2 Ib S02 per minion BTU heat Input and
removal efficiencies approaching 90 percent long term average for high
sulfur coals,
2. Variability of one system was a significant problem owing mainly to
the interimlttent operation of boiler and scrubber In combination. Where
continuous operation was achieved at the other sites, variability of scrubber
performance was minimized. -
3. Monitor availabilities and reliabilities varied from 33.3 to 85.7 on
a "total days" basis, which is still not up to capabilities of state of the art
monitoring technology.
3- 37
-------
3.3 PERFORMANCE TEST REPORT B
This test report includes results of monitoring the performance of
FGD systems at TVA's Shawnee FGD test facility and at the Lawrence No. 4 steam
generator of Kansas Power and Light Company. These tests were performed
by E-PA with, emphasis, upon obtaining. 30 continuous days of SO- data,
using monitors certified according to procedures in the October 6, 1975,
Federal Register.
At the Shawnee site, a venturi scrubber using limestone with adipic
acid additive was monitored for 49 continuous days with the existing on-site
SO, monitoring system. Due to some monitoring problems, 31 days of data
were obtained (63 percent reliability) which showed average SQp emissions
of 0.22 lb/10 Btu and SOp emission reduction of 96.1 percent.
EPA used a mobile sampling van to obtain SQp data from the Lawrence
No. 4 FGD unit, a venturi scrubber with limestone applied to combustion of
low-sulfur coal. For the 22 days of continuous scrubber operation (with
two periods of interruption due to sampling pump failures), the SQp monitors
were 86 percent reliable, measuring average SQp emissions of 0.03 lb/10 Btu
and 96.6 percent SQp removal for 22 days. The relative variability in outlet
emissions from both sources were significantly higher than for previous tests,
due to the low absolute values of the data.
All instrumentation and procedures followed have been previously
discussed in section 3.2. A noteworthy exception is the mobile van
equipped with fluorescence analyzers for sulfur dioxide and polarographic/
paramegnetlc analyzers for oxygen at the Lawrence test site.
3-38
-------
At both installations, SCL and Og concentrations were measured
upstream and downstream of the FGD system using continuous instrumental
monitors. Copies of boiler operation logs and FGD system operation
logs were obtained to document process operating conditions during the
monitoring periods.
As in all cases, the instruments used to generate data have been
subjected to the appropriate test procedures (Federal Register, Vol.
40:194, October 6, 1975) to assure accuracy of all data reported herein.
3.3,1 Description of Test Sites
3.3*1.1 Shawnee FGD Prototypes, Tennessee^Valley Authority
The Shawnee Power Station, operated by the' Tennessee Valley Authority
(TVA), 1s a coal-fired steam generation station having 10 turbines, each
served by a boiler and stack. A portion of the exhaust gases from one of
these stacks is directed for use with three pilot plant scale wet scrubbers
systems - a venturi with a spray tower after absorber, a turbulent contact
absorber (TCA), and a marble bed absorber. Testing was performed on the
venturi/spray tower using limestone enhanced with adipic acid and the TCA using
lime only. This report describes the test and results for the venturi/spray
adipic acid enhanced limestone system.
The venturi system was manufactured by Chemical Construction Company
in the late 1960's and contains an adjustable throat which permits control
and variation of pressure droo. Mo design performance data are available.
Figure 3-16 is the process flow diagram for the Shawnee venturi system.
For this test, limestone and adipic acid were added to the scrubber effluent
hold tank .with-adipic acid concentrations maintained at 1500 parts per
million volume during the entire test period.
3-39
-------
UJ
I
I AIR >-
FUEL 0!L>-*["REHEATEft [—--;
FAN
PROCESS
WATER
HOLD TANK
VACUUM
FILTER
K
I
STACK
SAMPLE POINTS
OGAS COMPOSITION
®PARTICULATE COMPOSITION & LOADING
©SLURRY OR SOLIDS COMPOSITION
-GAS STREAM
-LIQUOR STREAM
Figure 3-16
Tennessee Valley Authority, Shawnee No, 10 Prototype Unit:
General Process Diagram,
DISCHARGE
StTTUHG i'ONU
-------
3.3.1.2 Lawrence Unit No. 4,KansasPowerand Light Company
The lewrence No. 4 steam generating unit 1s rated at 125 megawatt
electrical output and burns low-sulfur Wyoming coal with an average heating
value of 10,000 Btu/hr, sulfur content of 0.5 percent and ash content of
9.8 percent. The FGD system consists of two 50 percent capacity -scrubber
modules of a Combustion Engineering - Bed Scrubber/Spray Tower two-stage
system as shown in Figure 3-17. Pulverized limestone slurry contacts the
flue gas in both the rod scrubbers and spray tower. Overall SOp removal
'is designed for a minumum 73 percent, A detailed description of this system
may be found in EPA 600/7-78-Q58b pp. 255-276, "Proceedings of the Symposium
on Flue Gas Desulfurization, November 1977.
3-41
-------
-^EFFLUENT LINE
Figure 3-17 Kansas Power and Light, Lawrence No. 4 Operational FGO System;
Simplified Flow Diagram.
-------
3.3.2 Data Gather 1ji£ Systerns
3.3.2.1 ShawneeFGDPrototypes,. Tennessee Valley Aythorlty
A schematic diagram of the monitoring system used at each monitoring
location at Shawnee is shown in Figure 3-6. The sulfur dioxide (SOg)
instrument at each location is a DuPont 460 analyzer. The oxygen (02) analyzer
is a Thermox model HOG 3 instrument. The ranges of the scrubber inlet SOg
analyzers are set at 0-4000 ppm SOg and the ranges of the two scrubber outlet
S02 analyzers are 0-1000 ppm. The ranges of 02 analyzer are all set at
0-10 percent 0-. The SO, and 02 probes tips are located at the stack centers
with the 02 rpobe approximately one stack diameter upstream of the S02 probe
at each location. The analyzers operating on approximately 8-minute cycles
during which stack gas concentration measurements are made continuously except
for an automatic 1-minute backflush period. Concentration measurements are
recorded continuously on four strip chart recorders located in the scrubber
control room.
The moisture content correction for the SO- gas measurements was determined
from the temperature measurement in the sample gas stream immediately following
the knock-out trap in the analyzer case. This gas was assumed saturated at
this temperature. The moisture content correction for the 0, gas measurements
was the stack moisture content as the 0- analyzers measured a wet gas stream.
Mention of a'specific company or product name does not constitute endorsement
by the Environmental Protection Agency,
3-43
-------
3.3.2.2 Lawrence Unit No. 4. Kansas Power and Light Company
The monitoring system used at Lawrence No. 4 consisted of an extraction/
conditioning module and a mobile laboratory which housed the analyzers. Thermo
Electron Model 40 pulsed fluorescence analyzers were utilized to monitor sulfur
dioxide at both the inlet and outlet of the south scrubber. A Beckman Model 742
polarographic analyzer was used to monitor the inlet oxygen concentration while
a MSA paramagnetic analyzer was utilized to monitor outlet concentration of
oxygen.
Figure 3-18 contains a schematic diagram of the sample extraction/
conditioning module. Briefly, the system consists of a heated orobe with a
3/4 inch nozzle oriented away from the gas flow, a heated filter box/pump
box assembly, a refrigeration cooler and finally a distribution panel to
readily enable the sampling of calibration or sample streams. All connecting
lines from the probe to the refrigeration cooler consisted of 1/2 inch
O.D. Teflon tubing was used. A 0-15 psi back pressure regulator was placed at
the end of the exhaust vent line to cause a fraction of the gas from the source
to be transported through the analyzers.
Data acquisition was accomplished using an Accurex Auto Data Nine data
acquisition system with a 24-channel Ester!ine Angus multipoint recorder as
a backup 'in ciase of Auto Data Nine failure.
The extraction system was operated at a constant flow rate of approximately
">
1.5 ft /min with a constant back pressure of 5 psi. All heat traced lines
and heated boxes were operated at teroeratures ranging from 130°C to 200*0.
Sample flows to the oxygen analyzers were maintained at 1.6 ft /hr while
3-44
-------
i
•P»
in
Hi-Cerente Hullwil I
SuU|illng Pan I
• I S*iB|j|£
M ,-J I-iul,,-
Figure 3-18 Schematic of Monitoring System of Lawrence No. 4
-------
those for the S02 analyzers were not visually maintained as the analyzers,- , :
contained individual -sampling pumps which controlled the analyzer sample demand.
All analyzers were calibrated daily at approximately 0900 with a zero,
midscale and 90 percent of full-scale range standards. Data was collected
instantaneously at five minute intervals by' the Auto Data Nine. These data
printouts also contained secondary parameters such as line temperatures, .
cooler temperatures, etc.
Prior to the initiation of monitoring, a profile was conducted at both
the inlet and outlet to the scrubber in order to ensure a homogeneous gas .
stream. At the completion of this exercise, the probes were oriented as close
to the center of the duct as possible.
The invidivual analyzers were operated on the ranges shown in Table 3-3 and..
calibrated with the type of standard listed.
TABLE 3-3. ANALYZER SPECIFICATIONS
Analyzer Location Range Calibration' Standard
TECO Model 40
TECO Model 40
Beckman Model 742
MSA Paramagnetic
Analyzer
3.3.3 Data Reduction
Inlet
Outlet
Inlet
Outlet
Procedures
0-1000 ppm
0-100 ppm
0-10*
0-10%
S02/air
S02/air
°2/N2
°2/N2
The types of data that were collected for reduction purposes were:
inlet SO- strip chart (2 inlets)
inlet ^2 strip chart (2 inlets)
outlet S02 strip chart (2 outlets)
outlet 02 strip chart (2 outlets) '
3-46
A
-------
scrubber logs (Including boiler load and -coal feed rate)
instrument logs
instrument calibration data sheets
manual test results
The data were first logged in as received and then were reviewed for
possible data gaps. The charts were then transcribed to a tabular format
using a strip chart data digitizer. The tabular data were then processed
through a manual keypunch operation so that appropriate scale factors, moisture
values, process data, and descriptive comments could be included prior to data
listing. The punched, cards were then processed by computer to obtain a data
listing and calculated results for each 15 minute data point. The data,listings
were reviewed by the EPA contractor for keypunch or other transcription errors.
The scrubber and instrument logs were reviewed so that periods of boiler outage,
scrubber outage, bypass, startup or shutdown could be properly identified and
coded so that these data would not be included in the calculation of averages
and summaries.
After data editing was completed, average summaries were prepared.
Averages based on the 15-minute data were prepared for consecutive 1-hour,
3-hour, 3-hour, and 24-hour intervals. In order to calculate an average
result for a single interval, it was specified that at least 75 percent of
the 15-minute data points be available for that interval. For example, an
8-hour average could only be calculated when 24 of the possible 32 15-minute
data points were available. When less than 75 percent of the data were
available for an interval, an average was not calculated and blanks were
entered in the summary printouts.
After each 30 days of average interval data, a statistical summary
was prepared to determine the following parameters for the average.
3-47
-------
mean standard deviation
average deviation maximum
minimum, .,, . . ' .rang?... „,,.,.
percent standard deviation
These parameters were calculated assuming the data were normally distributed.
The calculation procedures used to convert the analyzer outputs for
sulfur dioxide and oxyqen concentrations to mass emission factors are given
in 40 CFR 60 Subpart D. This procedure is known as the F-factor approach and
is outlined below.
20.9
20.9-02
TIW
Where £ » Emission factor - Ib/million Btu
C = S0? concentration - ppmv, wet basis
it
F * Stoichiometric conversion factor, 9820 dscf /mill ion Btu for
subbituminous coal
K = Conversion factor, 1.659 x 10" Ib/dscf per ppmv
0? = ^Xy96" concentration, percent by volume as measured
M * Moisture fraction as measured (for dried samples, M=0)
The sulfur dioxide and oxygen concentration results were obtained by multiplying
the strip chart readings as a percent of scale by the appropriate calibration
factor.
3-48
A
-------
The emission factor was calculated for each FGD system inlet and outlet test
point. The sulfur dioxide removal efficiency far a module is calculated by:
Efficiency * Ein oyt . x 100 percent
When more than one inlet and/or outlet test point was monitored, the total system
emission factors and sulfur dioxide removal efficiencies were calculated by a
weighted average procedure. The equation for this calculation for total system
efficiency is given by:
EFF total = EFFA (Fft) + EFFB(Fg)
Where,
system efficiency
EFF. = efficiency of module or module set A
F. = fraction of gas flow through module or module set A
EFFg = efficiency of module or module set B
F = fraction of gas flow through module or module set 3
3-49
-------
3.3.4 Data Analysis
_3.3.4.1 .....Data Calculation .Assumptions .. . .. . .
In previous SO- monitoring reports, sevtral assumptions were made due to
direct oxygen or moisture readings being unavailable, which led to a maximum
error level due to the assumptions of 3 percent in emissions and 0,5 percent
in percent removal efficiency.
For the data to be described, no assumptions were made.
3.3.4.2 Data Avai]j.b1Jj_ty.
Table 3-4 shows the data gathering breakdown for the two sites. The
total days sampling time was ascertained, then the boiler and scrubber down time
was subtracted to yield the net days available for scrubber performance data.
Data for each one-hour period was compiled and 24-hour periods characterized
as full data periods, i.e., when the boiler/scrubber system was operable
18 hours or more and 18 hours or more of monitor data was obtained within a
calendar day.
As shown in Table 3-4 the percentage data availability ranged from
63.3 percent total days at Shawnee to 84.6 percent at Lawrence No. 4 for
overall efficiency, where"both inlet and outlet data were available.
Comparison of performance at the Shawnee site to design is not possible
since the desiqn SIX, removal for adipic acid Injection is not known due to
the limited operating experience. What is significant is that the limestone/
adipic acid venturl system achieved 96,1 percent S(L removal on identical flue
gas to that which the lime-TCA FSD system previously reported an 88.6 percent
SO removal.
3-50
-------
TABLE 3-4 CATEGORIZATION OF DATA
Total Days
Boiler Down
Scrubber Down
Ul
<£l Net
Full Data Days
% Data Available
Shawnee Venturi FGD Lawrence FGD
49
0
0
49
31
63.3
37
0
11
26
22
84.6
-------
Comparison of the Lawrence performance to design SO, removal is
interesting in that the 73 percent design figure was easily exceeded by the
96.5 percent figure demonstrated during the 22 days testing. This is because
a slight overdesign-of'a-low salfur FGD"system-may show significant additional
$$2 removal when compared to similar overdesign of a high sulfur FGD
application. Another way of stating this is that removal of an extra 50 ppm
is very significant when there is only 60 ppm remaining, as compared to
when 600 ppm remain. This ease of scrubbing low sulfur coals was discussed
in EPA 600/7-78-030 b, March 1978, by Bechtil Corporation.
3.3.4.3 Statistical Analyses
Figures 3-19, 3-20, and 3-21 graphically illustrate FGD performance at
the Shawnee venturi site using limestone with adipic acid additive. Figure 3-19
shows inlet S02 loadings average 5.6 percent lb/10 Btu with a geometric
dispersion (GD) of 1.070. Figure 3-20 shows outlet SO- emissions averaging
0.22 lb/10 Btu with a GD of 1.518. Percent S02 emitted averaged 3.9 percent
(96.1 percent SO^ removal) for the 31 day period with a GD of 1.427.
Figures 3-22 through 3-24 show the performance of the Lawrence venturi-
spray FGD using limestone slurry. Figure 3-22 shows average inlet SO-
loadings of 1.02 lb/10 Btu, while Figure 3-23 shows average outlet SOg
'emissions of 0.03 lb/10 Btu. Geometric dispersions are 1.122 and 2.342 for
inlet and outlet respectively. In Figure 3-24 the percent SO, emitted is
shown to be 3.4 (96.6 percent S02 removal) with a GD of 1.885.
The hiqh geometric dispersions occur for both systems on the outlet and
percent emissions due to the extrememly low emission levels; the magnitude of
variance [e.g., x (g-1) and x/(g-l)l is smaller than for previous results from
FGD monitoring studies.
3-52
-------
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.
— -. • •:. ,--! -.---.-.•:• .= -
.. . .-•_ - T
T . . z T • - - • „-•-„: .T
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'•••• ' 1 4- i '"JJ1
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-•''I
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. - ...••-:•.. - - - •
• : . • - - ; . -:=-.: - .:-.-•-- v :
. ". : - ' "•-.-.
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t"--"-.--.----: '"_""•' J[ -
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t - tt
% '- ''''-'• 1 1 _L j-li
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• i-'-. .'t'-*"' ' T i:~
t ft' - ":.'. '-' "*" 1
It'' • • 1 • I -1 ii-
f- - .-- -;--••- X - .!.t
T :T *} - '6. 75
I 1 .;• , 1.9
• -{ - J - f
'
"[ 1 1
' '
i ^U.1 L
T'"-' h-|-—)-|--- -
1
fr|T-
-
.
" t
„
^ :-..-. .;
—
---
.r
"
-_ - r r
-
, lit
= 1.885
- 1
\
i_-
rn
i
-' - : -
r
- j
i
i
I
L . - -, _J
'
i
1
1
L
- -T.-
-
•hr
-=
-•
;j:-
a
7
6
5
3
2
1
j 10 79 30 40 50 60 70 80 90 95 03 99 99.N 99,9 99.99
-------
3.3.5 Conclusions
1. The two systems monitored in this report illustrate very low emissions
achievable with FGD systems on low sulfur coal with conventional limestone
scrubbing and on high sulfur coal with conventional limestone scrubbing
assisted by low concentrations (1500 ppm) of adipic acid.
2, The relative ease of SOn removal from low sulfur coal flue gas is shown
by the Lawrence data, where 96.6 percent S02 is removed.
3. The benefits of adipic acid injection are shown by comparison of the
system examined here compared to conventional lime scrubbing, where adipic acid
enhancement of limestone showed 96.1 percent SO, removal compared to 88.6 per-
cent measured on a parallel system with lime scrubbing only.
3-59
-------
3,4 DRY SO CONTROL
3.4,1 Introduction
Although a number of flue gas desulfurization processes which are
based upon lime/limestone wet scrubbing are commercially available,
the electric utility industry and flue gas desulfurizatiorv equipment
vendors have continued to develop alternative control technologies.
One of the major developments during the past two years is a dry SO-
control technology based upon spray 'dryers,
A simplified flow sheet for a typical spray dryer is shown in
Figure 3-26.The hot'flue gas (280 - 350° F) enters the spray dryer
contactor in which a slurry or concentrated sorbent solution con-
tacts the flue gas. The water which is associated with the slurry
or solution is evaporated by the hot flue ga's while simultaneously,
the sulfur oxide reacts with the alkaline reagent (either Na^CO,, GaO,
NaHCO or Ca(OH) ), and hence, the term spray dryer. The flue gas
which contains dried reagent, fly ash, and reaction products leaves
the spray dryer contactor, and the particulate matter is collected
with an electrostatic precipitator (ESP) or a baghouse. Baghouses
have a slight advantage over ESP's by allowing additional contact
between the flue gas and any unreacted sorbent leaving the spray
dryer. Since the flue gas leaving the spray dryer is "hot" (150 -
180° F), no reheat is required.
3-60
-------
Antelope Valley Station Flow Diagram
Boiler Flue Gas
Clean
Dust Collector Exhaust
Spray
Absorber
Powder & Fly Ash
SO? Absorbant
Partial Recycle
Figure 3-25
-------
3.4.2 Pilot Scale Testing,
Four pilot planes have been operated to develop design data and
to estimate the dry SO^ control system's operating and capital costs.
Four vendors have participated in the pilot acale test program which
is listed in Table 3-5. All of the pilot plants were operated under
3
the following conditions:
inlet gas temperature 310° F
inlet S02 concentration 400 - 2000 ppm
coal North Dakota lignite and
Powder River Basin sub-
bituminous coals
Both of the fuels used are highly alkaline. A typical analysis for
the Powder liver coal is given in Table 3-6. The fly ash contains an
average 20+ percent of lime; much of which is available for reaction
with the sulfur oxide. The effect of the fly ash alkalinity, which
is a source of lime, is to lower the apparent lime stoichiometric
ratio which is required to achieve a specified SC^ percent reduction.
2
For example, it has been reported that contacting water with the fly
ash laden flue gas in the spray, dryer can reduce S0» emissions by as
much as 60 percent. Based upon the pilot plant testing completed
to date, a relationship between percent reduction and stoichiometic
ratio for lime is given in Figure 3-27 for an alkaline fly ash. If a
coal which was not alkaline were used, the stoichiometric ratio,
would increase dramatically, by as much as a factor of two based
upon proprietary data.
3-62
-------
TABLE 3-5
SPRAY DRYER PILOT SCALE PROGRAM EXPERIENCE
Facility
Leland Olds Station
Vendor (s)
Atomics International/
Wheelabrator-Frye
Carborundum Company
Sorbents Tested
Soda ash, trona,
lime, limestone,
and ammonia
Comments
Two-month pilot testing
3000 actm size
100 hr continuous tests
up to 90% SOj reduction
reported^
HooL Lake Station
W.J. Neal Station
Joy/Niro
Babcock & Wilcox
Soda ash, fly ash,
lime, etc.
Soda ash, fly ash,
lime
Pilot plant testing at
20,000 acfm size
100 hr continuous run
3000 acfm pilot testing
100 hr continuous tests
up to 901 S02 reduction
reported
-------
TABLE 3-6
TYPICAL FUEL CHABACTEB.ISTICS
Sulfur, % 0.54
Moisture, % 28.92
Ash, % 7.89
High Heating Value, BTU/lb 8139
TYPICAL ASH ANALYSES
Compound Average Weight Percent
35.58
A120, . 16.82
CaO 20.27
MgO 3.45
3-64
-------
100
90
80
70
60
at
O
m
QJ
Pi
O
40
30
x = 70% SO- removal;
non-alKallne ash
coal (reference 6)
20
10
1 2
Ca/S Stoichiometric Ratio
FIGURE 3-27
PERCENT SO2 REMOVAL AND STOICHIOMETRIC
RATIO FOR ALKALINE ASH COALS5
3-65
-------
To demonstrate the impact of the alkalinity on effective
stoichiometric ratio, the stoichiometric ratio has been calculated
.based upon 50 percent of the fly ash lime being chemically available
and the lime addition rate. For the coal listed in Table 3-6, and a
550 MWe boiler, the stoichiometric ratio based upon lime addition
rate and entering S02 is 1.12. The fly ash, assuming 50 percent
availability of the lime, would contribute to the stoichiometric
ratio an additional 0.8 units. The effective stoichiometric ratio
within the spray dryer would be 1.92.
The significance of stoichiometric ratio becomes apparent when
the operating and maintenance component of the total annual revenue
requirement Is estimated. As the stoichiometric ratio increases at
a constant sulfur oxide percentage reduction requirement, the reagent
and waste disposal cost also increase.
3.4.3 Economics ' - .^r'^- •' • *•"
Since dry S02 scrubbing systems'"combine sulfur oxide and particulate
matter control into a single process. The projected costs of dry SCL
control .are based upon the incremental flue gas desulfurization cost.
The cost was estimated by extracting the particulate control costs
from the published total capital cost. The cost of a spray dryer
flue gas desulfurization system exclusive of particulate control costs
is estimated at $30-4Q/KW. Table 3-7 is an estimate of the operating
and maintenance costs for a typical dry S0_ control system for a
3-66
-------
Table 3-7 - Economics of Dry SO2 Control
Total Capital
Investment S KM
1.68
30.30
Coal Sulfur content
HFU
.2.3
30.30
4.0
30.30
O&M Costs
Lime
Labor
Replacements
Power Costs
Disposal
TOTAL
2,678,000
454,000
500,000
213,000
525,000
4,370,000
3,666,000
454,000
500,000
213,000
718,000
5,551,000
6,376,000
454,000
500,000
213,000
1,250,000
8,793,000
O&M Mills/KWH
1.5
1.9
3.1
Based Upon: 500 MWe Plant, 701 Ranoval
65% load Factor
$4Q/*Fon of Lime
$5/Ton Waste Disposal Cost
Non-Mkaline Ash (1977 Dollars)
-------
variety of coal sulfur contents. At a constant percentage reduction,
Table 3-7 shows the impact of increasing reagent and waste disposal
costs.. The -lime and waste disposal -cost.- expressed 'as a fraction of
the total OfiiM cost increases from 73 to 87 percent as the coal sulfur
content increases from 1.68 to 4.0 pounds of S0? per million BTU.
An economic comparison between wet and dry flue gas desulfuri2ation
processes is given in Figure 3-28 for alkaline coals. The coal sulfur
characteristics which are used in the EPA economic model are described
in Table 3-8, At 70 and 85 percent removal, dry SO, control systems are
less costly than wet scrubbers for alkaline ash coals. The economic
comparison between wet and dry flue gas desulfurization systems for
non-alkaline coals is given in Figures 3-29 and 3-30 for 70 and 80 percent
SO, control respectively. Based on the data available, 70 percent
SO- reduction using dry SO, control technology appears to be less
costly than wet scrubbers for coals which contain less than about
3.5 pounds of SO^ per million BIO. If the level of control is
increased to 80 percent, the maximum coal sulfur content which cam
be economically treated by dry SO. control systems decreases to about
3 pounds of S02 per million BTU.
Since all of the published test results are for alkaline coals,
the uncertainty in the stoichiometric ratio which is required to
achieve a 70 percent reduction for nonalkaline coals is larger than
for alkaline coals. This uncertainty could have a significant impact
on the O&M costs because the reagent and waste disposal costs are about
70-85 percent of the operating and maintenance requirements. An error of
3-68
-------
Table 3-8
REPRESENTMTOE CffiLS USED IN EPA's ECONCMIC MODEL
Designation
A
B
D
Pounds of SO2/
Million BTU
0.8
1.2
1.7
Coal Sulfur
Content, %
0.4
0.6
0.68-0.8
3.3
1.32-1.65
5.0 2.5
greater than 5.0 greater than 2.5
Goal Rank
SubbitunrLnous
Subbituminous
Subbituminous, bituminous
lignite
SubbitamLnous, bituminous
lignite
Bituminous
Bituminous
-------
Economic Gonparison Between «et and Dzy POD Processes
• AT 7-0% .932 -Removal (Alkaline ftsh)
•"^
I
ABC
I.I I .
1 ~"" 2
Pounds of SO2 per Million BTO
FIGURE 3-28
3-70
-------
Econotiie Cemparison Between Wet and Dry PGD Processes
at 70% SC>2 Removal (Non-Alkaline Ash)
f 4
ED
r—i
I
WET
- DKf
B D
_L
r
Pounds of S3
45
Million BTU
FIGURE 3-29
3-71
-------
Eoananic Comparison Between *fet and Dry FCD Processes
at 80% Removal (Non-Alkaline Ash)
5 r
CRY
B
Pounds of SQ2 per Millicai HKJ
FIGURE 3-30
3-72
-------
10 percent in the stoichiomctric ratio could reduce the maximum coal
sulfur content which could be economically treated by dry SO control
from 3.0 to about 2.6 pounds of S02 per million BTU, a 13.31 reduction
in the maximum coal sulfur content (see Figure 6).
3.4.4 Envl^rpnmental^ and Energy Impact^
In addition to lower costs, dry SO. control offers other
advantages over wet scrubbers. These advantages include:
a. The dry system requires no wet sludge handling equipment.
Although the amount of waste produced on a dry basis is
larger for a dry scrubber than a wet system, it appears to
be easier to dispose of and handle.
b. The dry system requires approximately 25 to 50 percent of
the energy required for a wet system,
c. The dry scrubber will use about 30 to 50 percent of the
amount of water required for the wet systems,
d. Although reliability data on dry systems are limited, due
to the simplicity of the flov? sheet, dry systems could have
availabilities significantly higher than for conventional
wet limestone scrubbers.
Because of its economic advantages and potential for increased
reliability, the dry SO^ control system has attracted utility and
industrial interest. To date, five systems have been ordered. Two
of the systems are for industrial boilers and three of the systems
are for utility boilers. A listing of the "on order" dry SCL
control system is given in Table 3-9.
3-73
-------
Uncertainty in Economic Comparisons
At 70% SO2 Removal
1
•y
Wet Flue Gas Desulfurization
o~ Dry Flue Gas Desulfurization
1
B
1
234
Pounds of S02 Per Million BTU
FIGURE 3-31
3-74
-------
Utility/Conpany Station/Plant
TABLE 3-9
Dry S02 Control Systems on Order
Capacity Coal Sulfur Lb, Start up
(MW/SCEM) of SO2/Mill .Btu Status Date
Basin Electric
Power Coop
Basin Electric
Power Coop
Celanese Corp.
Strathmore Paper
Company
2.1
Antelope Valley 1 455 MW
Larsmie River 3 550 MW
Otter Tail Power Coyote 1 400 MW
Cumberland Plant 57,700 SCFM 1.7
Wbronoco Plant 22,000 SCFM N/A
2.0
2.4
Contract 11/81
Awarded
Contract 4/82
Awarded
Under Con- 5/81
struction
Contract 12/79
Awarded
Under Con- 5/79
struction
Longterm %
of 902 Removal
78
85
50
70
N/A
-------
3.4.5 References
1. Estcourt, V.F,, Crutle, R.O.M., Gehri, D.C., and Peters, H.J.
Tests of a Two-Stage Combined Dry Scrubber/S0? Absorber Using
Sodium or Calcium. Presented at the 40th Annual Meeting
American Power Conference, Chicago, Illinois, 26 April 1978.
2. Personal communication from R. Eriksen, Basen Electric. Power
Cooperative.
3. Janssen, 1. and Eriksen, E..L-. Basin Electric's Involvement
with Dry Flue Gas Desulfurization, 5th Symposium on Flue Gas
Desulfurization, Las Vegas, Nevada, 5-8 March 1979.
4, Letter to Mr. Fred Longenberger from Mr, R.L. Eriksen,
21 November 1978.
5. The Dry Scrubber for Flue Gas Desulfurization and Particulate
Control, Niro Atomizer/Joy Manufacturing Company.
6. Pirstenberg, H, Prevention of Significant Deterioration
Application for the Installation of a Coal-Fired Boiler and
Associated Facilities at the Amcelle Plant in Cumberland,
Maryland, NUS-3232.
7. Personal communication from B. Laski, PEDCO Environmental.
3-76
-------
4. PARTICULATE
4,1 INTRODUCTION
On September 19, 1978, EPA proposed revised standards for particulate
matter. The proposal was based on the particulate matter emission test data
contained in the Background Information Document (BID-proposal) for the
particulate matter emission standard (EPA 450/2-78-006a). The BID included
data on many subjects relative to particulate matter emissions from electric
utility steam generating units including performance data on ESP systems, bag-
house systems-, scrubber systems, FGD slurry carryover, and sulfuric acid
mist condensation.
In the September 19, 1978 proposal EPA indicated that it would continue
to investigate two areas of the particulate matter data base; (1) performance
of the new 350 MW baghouse controlled utility steam generating unit that
recently initiated operation, and (2) the potential interference of acid
mist with the measurement of particulate matter.
4.2 LARGE BABHOUSE CONTROL SYSTEMS
At the time these regulations were proposed, the largest baghouse-
controlled coal-fired steam generator for which EPA had particulate matter
emission test data had an electrical output of 44 MW. Several larger
baghouse installations were under construction and two larger units were
initiating operation. Since the date of proposal of these standards, EPA
has tested one of the new units. It has an electrical output capacity of
350 MW and is fired with pulverized, subbituminous coal containing 0.3
percent sulfur. The ng/J (0.1 Ib/million Btu) heat input emission limit.
This unit has achieved emission levels below 13 ng/J (0.03 Ib/million Btu)
heat input. The baghouse control system was designed with an air-to-cloth
2
ratio of 1.0 actual cubic meter per minute per square meter {3.32 ACFM/ft )
4-1
-------
and a pressure drop of 1,25 kilopascals (5 in HnO). 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, The data for each test run obtained for the facility are
summarized in the Table 4-1,
TABLE 4-1
Stack
Emission Rate
lb/10D BTU
.018
.016
.024
.007
.035
Efficiency
Percent
99.35
99.36
99.25
99.71
99.16
Electrical
Load
MW
362
362
362
362
306 .
4.3 PERFORMANCE TESTING - ACID MIST
EPA indicated in the September 19, 1978, proposal that it would continue
to investigate the suspected problem of acid mist interference with Method 5
performance testing. Such a situation was suspected to occur when testing
after an FGD system when a facility was firing high sulfur coal.
Since proposal, EPA conducted a series of tests on a 181 MW boiler
burning. 3% sulfur coal and equipped with an electrostatic precipitator
4-2
-------
designed for 98.6 percent particulate removal, followed by an S0? scrubber
using carbide lime slurry. Although this facility was not considered
the best control technology for particulate, it was adequate for demonstrating
the potential problem of acid mist interference with particulate measurement
techniques.
A set of tests were run in the stack following the SO- scrubber using
the two proposed performance test methods - EPA Method 17 which uses an in-
stack filter and EPA Method 5 sampling trafn which uses an out-of-stack
heated filter. The results of these tests are summarized in Table 4-2
below. Since these tests were run for the purpose of comparing methods, the
samples were taken at a single point in the stack.
TABLE 4-2
Emission Rate lb/10DBTU
TEST METHOD
SAMPLING
TRAIN
EPA 17
EPA 5
EPA 5
FILTER
TEMPERATURE (°F)
Stack ('-IBS)
320
340
1
0.0905
0.0986
0.0714
Run Number
2 3
0.1470
0.0895
0.0534
0.0927
0.0953
0.0577
Average
0.1127
0.0945
0.0608
Following the series of acid mist evaluation tests, EPA obtained data from
a compliance test conducted at a 194 MW boiler burning 3 to 4% sulfur coal and
equipped with an electrostatic precipitator designed for 99.6 precent particulate
removal followed by a limestone S0? scrubber. Although no"tests were conducted
at this facility to evaluate the affect of sampling temperature on the amount
4-3
-------
of participate measured, the stack emissions following the scrubber were
measured using EPA Method 5 at a filter temperature of 320°F with no apparent
acid mist problem in meeting the final standard of 0,03 lb/10 BID. The results
of this test are summarized below in Table 4-3:
TABLE 4-3
Run I Electrical Stack Emission Scrubber Inlet ESP Inlet Precipitator
Load Rate Emission Rate Emission Rate Collection
MW Ib/ltr 8TU lb/10 BTU lb/10 BTU Efficiency
1 190 0.0207 0.0203 6.99 99.71
2 185 0.0141 0.0165 7,63 99.78
3 192 0.0209 Not measured Not measured Not Measured
4-4
-------
5. NITROGEN OXIDES
5.1 INTRODUCTION
In developing the final NO standards, the Administrator considered
A
emission data and other new information received after proposal of the
standards. Some of this information was submitted with comment letters
received during the public comment period, while other information
was requested by the.Administrator. This new information is discussed
below.
5.2 INFORMATION RECEIVED AFTER PROPOSAL
The Administrator received a number of comment letters which
criticize the proposed 24-hour emissions averaging period for coal,
arguing that it would not give boiler operators the flexibility they
need to handle normal boiler problems which occur during day-to-day
.operation. As an aid in evaluating the emission variability expected
during normal operation of a boiler, the Administrator has evaluated
approximately 34 months of continuously monitored NO data from seven
A
coal-fired boilers. The boilers are described in Table 5-1 and the
continuously monitored NO data appear in Table 5-2. All but six •-""•
X
months of these data were received after proposal of the standards.
5-1
-------
Table 5-1.
PLANTS SUBMITTING CONTINUOUSLY MONITORED NOX EMISSION DATA
Station1
and Company
Colstrip #1.
Montana Power
Colstrip #2,
Montana Power
Harrington #lf
Southwestern Public
Service
Muskogee #4,
Oklahoma Gas and
Electric
Boiler #4,
Adolph Coors
Huntington Canyon flt
Utah Power and Light
Ghent fl,
Kentucky Utilities
Coal
SUBB
SUBB
SUBB
SUBB
SUBB
W BIT
E BIT
Boiler
Manufacturer
CE3
CE
CE
CE
CE
CE
CE
Electrical
Output, HW
350
350
360
550
(25)'
430
510
Monitor
Certification
Date
Not s
Certified
Not ,
Certified
7/78
2/78
11/77
3/78
9/78
1 All boilers are required to comply with a NO emission limit of 300 ng/J (0.7 Ib/million Btu)
heat input,
2 SUBB is subbitumlnous coal; W BIT is Western bituminous coal; E BIT is Eastern bituminous coal.
3 CE is Combustion Engineering, Incorporated. fi
4 This boiler does not generate electricity. Its input rate is about 73 MW (250 x 10 Btu/hr).
If electricity were generated, 73 MW input would generate roughly 25 MW electrical output.
5 Although these monitors are not certified, in April and June of 1978 the monitors' performance
was evaluated by EPA and determined to be satisfactory. The monitor data appear to be biased high,
but probably by less than 21 ng/J (0.05 Ib/million Btu).
-------
Table 5T;2. SUMMARY OF CONTINUOUSLY MONITORED NOX EMISSION DATA
tn
GJ
Station Month Days of
and Company and Year Useful Data
Colstn'p #1, 10-77
Montana Power
n
12
1-78
2
3
4
5
6
7
8
9
1.0
28
30
31
31
28
30
28
0
27
25
19
28
31
9
Monthly Average NO Emissions 24-hour Periods Above:
nq/J (Ib/milll6n Btu)
205
175
155
140
130
140
140
-
135
170
170
195
205
(0.48)
(0,41)
(0.36)
(0.33)
(0.30)
(0.33)
(0.32)
-
(0.31)
(0.39)
(0.39)
(0.45)
(0.48)
210
15
2
1
0
0
0
0
-
0
1
3
7
16
260
2
0
0
0
0
0
0
-
0
0
1
1
1
300 ng/J
0
0
0
0
0
0
0
-
0
-0
0
0
0
-------
Table 5-2. SUMMARY OF CONTINUOUSLY MONITORED NQX EMISSION DATA
(continued)
Station Month
and Company and Year
Colstrip #2, 10-77
Montana Power
11
12
1-78
« 2
-F»
3
4
5
6
7
8
9
10
Days of
Useful Data
14
24
31
22
27
17
4
30
29
28
26
27
31
Monthly Average NO Emissions 24-hour Periods Above:
nj/J (1b/mni18n Btu)
185
145
160
170
190
130
140
185
240
230
240
205
180
(0.43)
(0,34)
(0.37)
(0.39)
(0.44)
(0.30)
(0.33)
(0.43)
(0.56)
(0.53)
(0.56)
(0.48)
(0.42)
210
1
0
1
2
4
3
0
5
25
21
26
12
5
260
0
0
0
0
0
0
0
1
5
6
7
0
0
300 ng/J
0
0
0
0
"o
0
0
0
0
0
0
0
0
-------
Table 5-2. SUMMARY OF CONTINUOUSLY MONITORED NOX EMISSION DATA
(continued)
en
tn
Station
and Company
Harrington #1 ,
Southwestern Public
Service
if
Muskogee #4,
Oklahoma Gas and
Electric
Boiler #4,
Adolph Coors
II
Month
and Year
7-78
3
9
2-78
3
10-77
11
12
1-78
Days of
Useful Data
17
17
3
21
15
5
15
27
1
Monthly Average NO Emissions 2*-hour Periods Above:
ng/J (Ib/milliSn Btu)
190
235
250
200
155
305
335
325
245
(0.44)
(0.55)
(0.58)
(0.46)
(0.36)
(0.71)
(0.78)
(0.76)
(0.57)
210
3
14
2
4
0
5
15
27
1
260
0
2
1
0
0
5
15
27
0
300 ncj/J
0
0
0
0
0
4
15
19
0
-------
Table 5-2. SUMMARY OF CONTINUOUSLY MONITORED NOX EMISSION DATA
(continued)
Ul.
1
en
Station
and Company
Huntington Canyon II,
Utah Power and Light
Ghent #1,
Kentucky Utilities
Month
and Year
2-78
2-79
3
Days of
Useful Data
14
8
26
9
Monthly Average NO Emissions'
~
24-hour Periods Above:'
225
260
220
190
(0.52)
(0.60)
(0.51)
(0.44)
210
7
8
14
0
260
0
4
0
0
300 ng/J
0
0
0
0
1 Some months contain less than 30 days of useful data. This is because during these months the boiler or
the NO monitor was out of service for periods of time greater than 24 hours.
A
2 This is the average of all 24-hour averages of NO data available during the calendar month. Some 24-hour
periods contain less than 24 hours of useful data due to the boiler or the NO monitor being out of service.
3 Listed are the number of 24-hour averages of NO data which are above the specified emission limits during
the calendar month. All boilers listed in the table are required under 40 CFR Part 60, Subpart D to comply
with a NO limit of 300 ng/J {0.7 Ib/million Btu) heat input. If construction of the boilers had commenced
after September 18, 1978, however, the boilers would be subject under 40 CFR Part 60, Subpart Da to the
lower limits indicated. The 260 ng/J (0.6 Ib/million Btu) limit applies to new electric utility boilers
which burn bituminous coal, and the 210 ng/J (0.5 Ib/million Btu) limit applies to new electric utility
boilers which burn subbituminous coal.
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All of the.continuously monitored NO data were collected by plant
A
personnel as part of a regular monitoring program. Although EPA has
not evaluated all of these monitoring programs, it is believed that the
data accurately reflect the range of emissions expected during normal
operation of the boilers. This is because (1) five of the seven boilers
have NO monitors which have passed certification tests; and (2) the
other two boilers, located at Col strip, Montana, have monitors which
have been thoroughly evaluated by EPA. The Colstrip monitors appear to
be biased high, but by no more than about 21 ng/J (0.05 Ib/million Btu)
heat input. Thus, the Administrator considers the Colstrip data useful
in evaluating emission variability during day-to-day operation.
The continuously monitored data are from boilers which are required
by EPA regulations (40 CFR Part 60, Subpart D) to comply with a NO
A
emission limit of 300 ng/J (0.70 Ib/million Btu) heat input. The
boilers were not required to operate at lower NO levels during the
A ,
periods of time when data were submitted. Nevertheless, it appears
that most of the boilers were operated at somewhat lower levels.
The Administrator considers these data useful in evaluating the emissions
averaging period because they indicate the emission variability to be
expected during day-to-day operation of a utility boiler. Also, the
data are useful in that they generally support the final NO standards
A
for bituminous and subbituminous coals.
The continuously monitored NO emission data from the Adolph
X
Coors boiler are unusually high. These emission levels are atypical
of normal operation because the data were purposely selected to
EPA Hemorandum. Winton Kelly to Files (78-SPP-27). Review
of Available NO Data from Colstrip Units 1 and 2, Montana
EP/
5-7
Power Company. xMarch 13, 1979. EPA Docket Number IV-B-49.
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represent periods of time when emissions were highest. Ordinarily,
emission levels are below the applicable NO standard for this boiler
of 300 ng/J (0.70 Ib/million Btu) heat input. Sometimes, however, it
is necessary to supplement the fuel with natural gas to maintain these
levels. The Adolph Coors Company is uncertain about why NO emissions
J\
from this boiler are higher than expected, necessitating the periodic
use of natural gas. The Company speculates that their special boiler
design which is needed to burn an unusually dirty coal supply may
encourage NO formation.
While contacting electric utilities for continuously monitored
NO data, the Administrator received performance test results from
A
two utilities. These data are presented in Table 5-3. A performance
test is conducted with standardized EPA test methods and is used to
determine whether a new boiler is initially in compliance with EPA
standards. The Administrator has also received emission data used
to determine the relative accuracy of a continuous NO monitor.
A
These data are presented in Table 5-4.
On November 8 and 9, 1978, at the Second EPRI NO Control
A
Technology Seminar in Denver, Colorado, technical papers were
presented by the four major boiler manufacturers. These papers
5-8
A
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Table 5-3. PERFORMANCE TEST DATA
Station1
and Company
Coal
Boiler
Manufacturer
Electrical
Output, MW
Performance
Test Date
2
NO Emissions,
ng/J fib/mm ion Btu)
Test #1
Test #2
Test #3
Average
Columbia #2,
Wisconsin Power
and Light
Subbituminous
Combustion
Engineering
520
May 16, 1978
255 (0.59)
260 (0.61)
260 (0.61)
260 (0.60)
Morrow #1 , j
South Mississippi
Electric Power
Bituminous
Riley Stoker
220
. October 11, 1978
210 (0.49)
135 (0.31)
115 (0.27)
155 (0.36)
1 These boilers are required to comply with a NO emission limit of
300 ng/J (0.7 Ib/million Btu) heat input.
2 Each test was performed using EPA Reference Method 7 and consists
of the average of four individual concentration measurements (grab
" • samples). A "performance test" is defined as the average of three
individual tests and is used to determine compliance with EPA
emission limits.
5-9
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Table 5-4. REFERENCE METHOD TEST DATA
Station
and Company
Coal
Boiler
Manufacturer
Electrical
Output, MW
Test Date
2
NO Emissions,
ng/J tlb/million Btu)
Test #1
Test 12
Test #3
Test #4
Test 15
Test 16
• • Test 17
Test iB
Test 19
Presque Isle #7,
Upper Peninsula
Generating
Bituminous
Riley Stoker
80
October 6 & 7, 1978
215 (0.50)
215 (0.50)
260 (0.60}
225 (0.52)
225 (0.52)
200 (0.47)
220 (0.51)
225 (0.52)
205 (0.48)
1 This boiler is required to comply with a NO emission limit
of 300 ng/J (0.7 Ib/million Btu} heat input.
2 Each test was performed using EPA Reference Method 7 and
consists of the average of three individual concentration
measurments (grab samples). The tests were used to
determine the relative accuracy of the continuous monitoring
system, (The continuous monitor data are not presented here.)
5-10
A
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were considered by the Administrator in developing the final NO standards
and are referenced as footnotes 1-4.
Due to the large number of comment letters received it was
impossible for the Administrator to address in the preamble to final
standards all issues raised in the comment letters, or to present in
this document all of the new information received. Nevertheless, all
comments and new information, as well as EPA memorandum relevant to the
final NO standards, may be examined in the docket. (The docket is
J\
open for public review, as explained in the preamble to the final
standards,) The most detailed comments on the proposed NO standards
were prepared by KVB, Incorporated, for the Utility Air Regulatory
Group.
Barsin, J. A. Pulverized Coal Firing NO Control. Babcock and Wilcox
Company, Barberton, Ohio. EPA Docket Number IV-B-21.
2
Marshall, J. J., and A, P. Selker. The Role of Tangential Firing and
Fuel Properties in Attaining Low NO Operation for Coal-Fired Steam
Generation. Combustion Engineering, Inc., Windsor, Connecticut.
EPA Docket Number IV-B-21.
3
Rawdon, A. H.5 R. A, Lisauskas, and F. J. Zone. Design and Operation of
Coal-Fired Turbo Furnaces for NO Control. Riley Stoker Corporation,
Worcester, Massachusetts. EPA DScket Number IV-B-21.
4
Vatsky, J. Experience in Reducing NO Emissions on Operating Steam
Generators. Foster Wheeler Energy Corporation, Livingston, New Jersey.
EPA Docket Number IV-B-21.
5
Evaluation of the Proposed NSPS for NO Emissions from Coal Fired Utility
Boilers. KVB, Incorporated, Houston, Texas. Report Number 24300-390/R2.
January 1979. (Prepared for the Utility Air Regulatory Group.) EPA
Docket Number IV-D-611.
5-11
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A
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6. ENVIRONMENTAL IMPACT STATEMENT SUMMARY
6.1 INTRODUCTION
On September 19, 1978 (43 FR 42154), the Administrator proposed
standards of performance for new, modified, and reconstructed electric
utility steam generating units under the authority of the 1977 Clean
Air Act Amendments. That action was accompanied by publication of a
draft Environmental Impact Statement consisting of the following four
documents:
A. "Electric Utility Steam Generating Units: Background Information
for Proposed NOV Emission Standards," EPA 450/2-78-005a;
X
B. "Electric Utility Steam Generating Units" Background Information
for Proposed Particulate Matter Emission Standards," EPA 450/2-78-0060;
C. "Electric Utility Steam Generating Units: Background Information
for Proposed S02 Emission Standards," EPA 450/2-78-007a; and
D. "Electric Utility Steam Generating Units; Background Information
for Proposed SO^ Emission Standards - Supplement," EPA 450/2-78-QQ7a-l.
Notice of the draft Environmental Impact Statement's availability was
also published in the Federal Register on December 4, 1978 (43 FR 56722).
This document is the final Environmental Impact Statement (document E
in Table 6-1) which updates the draft statement. A cross-index to the
information developed prior to the Administrator's final action is contained
in Table 6-1. This table provides an index to the Background Information
6-1
-------
documents (listed above), other information documents (listed in section
6.3), and Federal Registers which describe the alternative actions
considered and their impacts,
6.2 PUBLIC COMMENTS
Over 700 comments were received on the proposed regulations. A
summary of these comments is given in section 2 of this document.
Revisions were made to the proposed regulations in response to these
comments. A description of these revisions, an analysis of suggested
revisions which were not made, and the rationale for the final action
taken by the Administrator are presented in the preamble to the
promulgated regulations.
6.3 ENVIRONMENTAL IMPACTS
The following studies were done prior to proposal to investigate the
impact of applying flue gas desulfurization systems to new, modified,
and reconstructed electric utility steam generating units:
1. "Flue Gas Desulfurization Systems: Design and Operating
Parameters, SCL Removal Capabilities, Coal Properties and Reheat."
2. "Flue Gas Desulfurization System Capabilities for Coal-Fired
Steam Generators."
3. "Boiler Design and Operating Variables Affecting Uncontrolled
Sulfur Emissions from Pulverized Coal-Fired Steam Generators."
4. "Effects of Alternative New Source Performance Standards on
Flue Gas Desulfurization System Supply and Demand."
5. "Evaluation of Physical Coal Cleaning as an SO-.Emission Control
Technique."
6. "The Impact of Modification/Reconstruction of Steam Generators
on SOp Emissions."
6-2
A
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7. "The Energy Requirements for Controlling SO- Emissions from
Coal-Fired Steam/Electric Generators."
8. "The Solid Waste Impact of Controlling S02 Emissions from
Coal-Fired Steam-Electric Generators,"
9. "Water Pollution Impact of Controlling SCL Emissions from
Coal-Fired Steam/Electric Generators."
10. "Participate and Sulfur Dioxide Emission Control Costs for
Large Coal-Fired Boilers."
11. "Review of New Source Performance Standards for S02 Emissions
from Coal-Fired Utility Boilers."
12, "The Effect of Flue Gas Desulfurization Availability on Electric
Utilities."
13. "Effects of Alternative New Source Performance Standards for
Coal-Fired Electric Utility Boilers on the Coal Markets and Utility Capacity
Expansion Plans."
14. "Flue Gas Desulfurization System Manufacturers Survey."
15. "Assessment of Manufacturer Capacity to Meet Requirements for
Particulate Control in Utility and Industrial Boilers,"
16. "Flue Gas Desulfurization Cost for Large Coal-Fired Boilers,
August 10, 1978."
17. "The Ability of Electric Utilities with FGD to Meet Energy
Demands."
These studies describe the impacts of applying wet system FGD
technology for control of SCL emissions. In addition to these studies,
further analyses of the impacts of using dry as well as wet SO^ control
systems have been completed. The preamble to the promulgated regulations
6-3
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gives the impacts of wet and dry controls for the final alternatives
considered. A discussion of dry1controls is presented in section 3.4
of this document.
The ICF Incorporated Coal and Electric Utilities Model has been
used to evaluate the impacts of all alternatives considered. The results
of the ICF computer analyses and a description of alternatives considered
are presented in the preamble to the proposed standards (43 FR 42154)', a
correction notice published November 27, 1978 (43 FR 55258), a notice
published December 8, 1978 (43 FR 57834), the preamble to the promulgated
regulations, and the docket.
6.4 SUMMARY OF IMPACTS FOR FINAL ALTERNATIVES CONSIDERED
The preamble to the promulgated regulations discusses the final
alternatives considered. With the alternative selected, dry or wet SO-
control systems can be used on low-sulfur coals and wet systems can be
used on all other coals. Dry control systems, which are more cost-
effective on low-sulfur coals, reduce the water, solid waste, energy,
and economic impacts of the final standards relative to the proposed
standards. The environmental impacts of wet and dry S02 control systems
and NO and participate matter control systems are summarized in Table
A
6-2. This table illustrates the impacts of (1) not revising the current
standards, (2) the proposed standards, and (3) the final standards
relative to a baseline of no emission control at all. The current
standards had negligible water, solid waste, energy, and economic impacts
because compliance with about two-thirds of all new units currently under
construction is being achieved by use of low-sulfur coal rather than FSD
systems. The final standards, which apply to all new units that commence
construction after September 19, 1978, will result in less air pollution
6-4
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emissions and small, incremental increases in solid waste, energy, and
economic impacts due to the application of scrubbing equipment. In the
analyses of environmental impacts, all new facilities affected by the
revised standards were assumed to have installed SCL control equipment.
6-5
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Table 6-1
Environmental Impact Cross-Index
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within Documents
Background and description of
proposed action.
Summary of proposed standards,
Statutory basis for proposed
standards.
Facilities affected by the
standards.
Availability of control.
Alternatives to the action
taken.
Costs and economic impacts.
A summary of the background is
given in Chapter 1 of documents
A, B, C, and E.
A summary of the proposed standards.
is given in the Federal Reg_is_ter
(43 FR 42154).
The statutory authority is summarized
in section 2.1 of documents A and B
and section 1.2 of document C,
A description of the affected facility
is given in chapter 3 of documents A
and B, section 5.1 of document C, and
the proposed and final Federal
Register notices.
Information on available emission
control systems is given in chapter 4
of documents A, B, C» and D and
chapters 3 and 4 of document E.
Alternatives considered in development
of the regulations are given in
chapter 6 of documents A and B,
chapter 4 of document C5 chapters 2
and 3 of document D, and in the
Federal Register (43 FR 42154,
43 FR 55258, 43, FR 57834, and the
preamble to the final action).
Additional analyses are contained in
the docket (OAQPS-78-1).
Cost analyses and economic impacts of
the alternatives considered are given
in chapter 8 of documents A and B,
chapter 7 of document C, chapters 2
and 3 of document D, chapter 3.4.3 of
document E, and in the Federal
Register {43 FR 42154, 43 FR 55258,
43 FR 57834, and the preamble to the
final action).
6-6
A
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Table 6-1
(continued)
Environmental Impact Cross-Index
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within Documents
Air quality impacts.
Water impacts.
Solid waste impacts,
Energy impacts.
Other impacts.
Impacts of action taken.
The effects on air quality are
described in section 7.2 of document
A, 7,1 of document B, and section
6.2 of document C. Estimated national
emissions of each alternative
considered are given in chapters 2
and 3 of document D, and in the
Federal Register (43 FR 42154,
43 FR 55258, 43 FR 57834, and the
preamble to the final action).
The water quality impacts are given
in section 7.3 of documents A and B,
section 6.3 of document C, and in
document 9.
The solid waste impacts are given in
section 7.3 of document A, section
7.2 of document B, section 6.4 of
document C, and 1n document 8 and the
preamble to the final action.
The energy impacts are discussed in
section 7.3 of document A, Section
7.4 of document B, section 6.6 of
document C, sections 2.4.2 and 3.2.2
of document D, document 7, and in the
Federal Register (43 FR 42154,
43 FR 55258, 43 FR 57834, and the
preamble to the final action).
The impacts upon coal, noise, and
other areas are given in section 7.3
of document A, section 7.5 of
document B, sections 6.5, 6.7, and
6.8 of document C, sections 2.4.1 and
3.2.3 of document D, documents 4, 12,
and 13, and in the Federal Register
(43 FR 42161, 43 FR 55258, 43 FR 57834,
and the preamble to the final action).
The air, water, solid waste, energy,
economic, and other impacts of the
alternative selected are dicussed in
the preamble to the final action.
6-7
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Table 6-2
CO
Matrix of Environmental and Economic
Impacts of Regulatory Alternatives
Relative to a Baseline of No Control
Adminis-
trative
Action
Proposed
Standards
Final
Standards :
Wet Control
Systems Only
Final
Standards :
Wet + Dry
Control
Systems
No Revision
to Current
Standards
Air
Impact
4.4**
+4**
+4**
+3**
Water
Impact
-]**
_!**
_•]**
_]**
Solid
Waste
Impact
_3**
-3**
_2**
-1**
Energy
Impact
-3**
?**
c
_2**
-1**
Economic
Impact
_3**
-3**
_2**
-2**
0
1
2
3
4
**
***
KEY
Beneficial Impact '
Adverse Impact
No Impact
Negligible Impact
Small Impact
Moderate Impact
Large Impact
Short-Term Impact
Long-Term Impact
Irreversible Impact
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