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

-------
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

-------
 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

-------
                   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

-------
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

-------
                     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

-------
                    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

-------
                         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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

-------
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"*
                                2-92

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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^
                                 2-93

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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
                               2-94

-------
           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

-------
            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.
                                 2-96

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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.
                                 2-97

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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).
                                 2-99

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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
                                2-101

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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.
                                2-104

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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.
                                2-105

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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
                                2-106

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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

                                 2-107

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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.
                                2-108

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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
                                2-109

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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.
                                2-110

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Averaging Time for Particulates




1.  D-461




Comment:  24-hour, average not justified by EPA on technical or




          economic basis.
                                2-111

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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.
                                2-112

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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
                                 2-113

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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
                                2-114

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possible violations.  The 20 percent limit has not been




met by four of the company's five wet scrubbers.
                     2-115

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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,
                                2-116

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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,
                                2-118

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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


                                  2-119

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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.






                                2-121

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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%




                                  2-122

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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.
                                  2-123

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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.
                                 2-124

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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.

                                2-129

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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)
                                2-130

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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.
                                2-131

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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
                                2-134

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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.







                               2-135

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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

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     •  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.
                                2-142

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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.)







                                2-144

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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.
                                2-154

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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.
                                 2-157

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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).
                               2-158

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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

-------
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

-------
          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

-------
          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

-------
          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.
                                 2-211

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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

-------
          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.
                                 2-213

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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

-------
          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

-------
          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

-------
          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.

                                 2-219

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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.
                                 2-221

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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.
                                 2-226

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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.
                                2-227

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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

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A

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                           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

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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

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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
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Figure  3-7    Conesville TCA/Llme
                35 Days  Inlet $02
        1.0
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-------
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-------
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-------
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-------
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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

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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

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                         -^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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-------
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-------
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

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                              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

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                          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.

-------
     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.

-------
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

-------
                   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

-------
         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

-------
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

-------
     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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