## SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

Draft Final Staff Report 

## Proposed Amendments to Regulation XX Regional Clean Air Incentives Market (RECLAIM) NOx RECLAIM

October 6November 

### December 4, 2015

Deputy Executive Officer Planning, Rule Developm ent, and Area Sources Philip M. Fine, Ph.D.
Assistant Deputy Executive Officer Planning, Rule Developm ent, and Area Sources Jill Whynot
Planning & Rules Director Planning, Rule Developm ent, and Area Sources Joe Cassmassi

Authors Minh Pham, P.E. – Air Quality Specialist Kevin Orellana – Air Quality Specialist
Reviewed By Gary Quinn, P.E. – Program Supervisor Danny Luong, P.E. – Senior Enforcement Manager William Wong – Principal Deputy District Counsel Barbara Baird - Chief Deputy CounselAcknowledgement The authors would like to thank the following st aff members for providing information for and participating in this project:
Planning, Rule Development & Area Sources Elaine Chang (retired), Shah Dabirian, Elai ne Shen, Priscilla Hamilton, Ian MacMillan, Barbara Radlein, James Koizumi, Ali Ghase mi, Susan Yan, Wayne Barcikowski
Engineering & Compliance Mohsen Nazemi, Danny Luong, Mitch Haimov, Bob Sanford, Fortune Chen, Susan Tsai, Kyu Kyu Remillard, Tran Vo, Paul Park, Connie Yee, Janice West, Khang Nguyen, Sawsan Andrawis, Rafik Beshai, Andrew Lee, John Yee and their team
Science & Technology Advancement Laki Tisopulos, Mike Garibay, Dipankar Sarkar, Peter Ko, Tom Lee, Glenn Kasai, Scott Wilson and their team
Information Management Chris Marlia, Ora McEwan, Xin Che n, Rezvan Ramezani, George Haddad

## Table of Contents

EXECUTIVE SUMMARY........................................................................................................... 1
B ACKGROUND
............................................................................................................................... ... 1 P ROPOSED BARCT, E MISSION R EDUCTIONS , AND RTC R EDUCTIONS .......................................................... 3 P UBLIC P ROCESS
............................................................................................................................... 7 CHAPTER 1 – BACKGROUND ................................................................................................ 12
L EGISLATIVE A UTHORITY ................................................................................................................... 12 N ON -A TTAINMENT S TATUS .............................................................................................................. 12 C ONTROL M EASURE CMB-01 OF THE 2012 AQMP ............................................................................ 13 C URRENT NO X RECLAIM P ROGRAM ................................................................................................. 14 NO X RECLAIM F ACILITIES ............................................................................................................... 16 CHAPTER 2 – FACILITY EMISSIONS AND RTC HOLDINGS........................................................ 18
P ROJECTED E MISSIONS AND E MISSION R EDUCTIONS .............................................................................. 18 A UDITED F ACILITY E MISSIONS AND RTC A LLOCATIONS ........................................................................... 19 M AJOR NO X S OURCES AT T OP E MITTING F ACILITIES .............................................................................. 21 CHAPTER 3 – 2015 PROPOSED BARCT AND EMISSION REDUCTIONS ..................................... 22
P REVIOUS BARCT D ETERMINATIONS ................................................................................................. 22 P ROPOSED 2015 BARC T ................................................................................................................ 22 C O -B ENEFITS OF E NERGY E FFICIENCY P ROJECTS .................................................................................... 24 CHAPTER 4 – COSTS AND CO ST EFFECTIVENESS.................................................................... 25

S TAFF ’ S P RELIMINARY E STIMATES ...................................................................................................... 25 C ONSULTANTS ’ E STIMATES ............................................................................................................... 26 S TAFF R ECOMMENDATIONS .............................................................................................................. 28 CHAPTER 5 - RTC REDUCTIONS............................................................................................. 31
R EMAINING E MISSIONS .................................................................................................................... 31 C ALCULATION M ETHOD FOR RTC R EDUCTIONS .................................................................................... 35 R EGIONAL NSR H OLDING A CCOUNT FOR E LECTRICAL E LECTRCITY G ENERATING F ACILITIES ............................ 35 S TAFF P ROPOSAL AND CEQA A LTERNATIVES ........................................................................................ 36 CHAPTER 6 – SUMMARY OF THE PROPOSED CHANGES IN RULE LANGUAGE AND DRAFT PROGRAM ENVIRONMENTAL ASSESSMENT ......................................................................... 40
R ULE 2002 ( F )(1) – BARCT P ROPOSED L EVELS AND RTC R EDUCTIONS ................................................... 40 R ULE 2002 ( F )(4) AND ( F )(5) – A DJUSTMENT A CCOUNT AND S TATE OF E MERGENCY R ELATED TO E LECTRICAL E LECTRCITY G ENERATING F ACILITIES ................................................................................................... 43R ULE 2002 ( I ) – RTC R EDUCTION E XEMPTION .................................................................................... 43 R ULE 2005 – R EQUIREMENTS FOR N EW E LECTRICAL E LECTRCITY G ENERATING F ACILITIES ............................ 44 O THER A DMINISTRATIVE A MENDMENTS .............................................................................................. 44 D RAFT P ROGRAM E NVIRONMENTAL A SSESSMENT (PEA) ....................................................................... 46 D RAFT F INDINGS UNDER C ALIFORNIA H EALTH AND S AFETY C ODE ............................................................. 47 PART I – BARCT ANALYSES FOR REFINERY SECTOR ............................................................... 52 APPENDIX A - REFINERY FLUID CATALYTIC CRACKING UNITS ................................................ 53
P ROCESS D ESCRIPTION ..................................................................................................................... 53 E MISSION I NVENTORY ...................................................................................................................... 54 A CHIEVED -I N -P RACTICE L EVEL FOR FCCU ........................................................................................... 55 C ONTROL T ECHNOLOGY ................................................................................................................... 57 C OSTS AND C OST E FFECTIVENESS FOR SCR S ......................................................................................... 64 C OSTS AND C OST E FFECTIVENESS FOR NO X R EDUCTION A DDITIVES .......................................................... 68 C OSTS AND C OST E FFECTIVENESS FOR L O TO X S CRUBBERS ...................................................................... 69 I NCREMENTAL C OSTS AND C OST E FFECTIVENESS ................................................................................... 71 S TAFF ’ S R ECOMMENDATION ............................................................................................................. 73 R EFERENCES FOR FCCU S .................................................................................................................. 74 APPENDIX B – REFINERY BOIL ERS AND PROCESS HEATERS ................................................... 77
P ROCESS D ESCRIPTION ..................................................................................................................... 77 E MISSION I NVENTORY ...................................................................................................................... 78 A CHIEVED -I N -P RACTICE NO X L EVELS FOR B OILERS AND H EATERS ............................................................ 78 C ONTROL T ECHNOLOGY ................................................................................................................... 78 C OSTS AND C OST E FFECTIVENESS FOR SCR S ......................................................................................... 83 S TAFF ’ S R ECOMMENDATION ............................................................................................................. 92 R EFERENCES FOR B OILERS AND H EATERS ............................................................................................. 96 APPENDIX C – REFINERY GAS TURBINES............................................................................... 98
P ROCESS D ESCRIPTION ..................................................................................................................... 98 E MISSION I NVENTORY ...................................................................................................................... 99 A CHIEVED -I N -P RACTICE NO X L EVELS FOR G AS T URBINES ....................................................................... 99 C ONTROL T ECHNOLOGY ................................................................................................................. 101 C OSTS AND C OST E FFECTIVENESS ..................................................................................................... 105 S TAFF ’ S R ECOMMENDATION ........................................................................................................... 112 R EFERENCES FOR G AS T URBINES ...................................................................................................... 113 APPENDIX D - COKE CALCINER ........................................................................................... 116
P ROCESS D ESCRIPTION ................................................................................................................... 116 E MISSION I NVENTORY .................................................................................................................... 116C ONTROL T ECHNOLOGY ................................................................................................................. 117 C OSTS AND C OST E FFECTIVENESS ..................................................................................................... 119 S TAFF ’ S R ECOMMENDATION ........................................................................................................... 121 R EFERENCES FOR C OKE C ALCINER ..................................................................................................... 122 APPENDIX E - SULFUR RECOVERY UNITS/TAIL GAS INCINERATORS ..................................... 123
P ROCESS D ESCRIPTION ................................................................................................................... 123 E MISSION I NVENTORY .................................................................................................................... 123 C ONTROL T ECHNOLOGY ................................................................................................................. 124 C OSTS AND C OST E FFECTIVENESS ..................................................................................................... 129 S TAFF ’ S R ECOMMENDATION ........................................................................................................... 134 R EFERENCES FOR SRU/TG I NCINERATORS ......................................................................................... 135 APPENDIX F - COMPARATIVE ANALYSES FOR FCCUS........................................................... 138 APPENDIX G - COMPARATIVE ANALYSES FOR BOILERS & HEATERS ..................................... 143 APPENDIX H - COMPARATIVE ANALYSES FOR SRU/TGUS.................................................... 148
APPENDIX I - COMPARATIVE ANALYSES FOR COKE CALCINERS ........................................... 151 APPENDIX J - COMPARATIVE ANALYSES FOR TURBINE/DUCT BURNERS.............................. 153
APPENDIX K – CO-BENEFITS OF EN ERGY EFFICIENCY PROJECTS........................................... 155 APPENDIX L – SURVEY QUESTIONNAIRES FOR REFINERY SECTOR ....................................... 157 PART II – BARCT ANALYSES FOR NON-REFINERY SECTOR.................................................... 160 APPENDIX M – CE MENT KILNS ........................................................................................... 161
P ROCESS D ESCRIPTION ................................................................................................................... 161 C URRENT E MISSION I NVENTORY ...................................................................................................... 161 C ONTROL T ECHNOLOGY ................................................................................................................. 162 P ROPOSED BARCT LEVEL AND E MISSION R EDUCTIONS ........................................................................ 164 C OST E FFECTIVENESS ..................................................................................................................... 165 R EVIEW OF ETS’ S A NALYSIS FOR C EMENT K ILNS ................................................................................. 167 R EFERENCES FOR C EMENT K ILNS ...................................................................................................... 169 APPENDIX N – CONTAINER GLASS MELTING FURNACES...................................................... 170
P ROCESS D ESCRIPTION ................................................................................................................... 170 C URRENT E MISSION I NVENTORY ...................................................................................................... 170 C ONTROL T ECHNOLOGY ................................................................................................................. 170 P ROPOSED BARCT LEVEL AND E MISSION R EDUCTIONS ........................................................................ 171 C OST E FFECTIVENESS ..................................................................................................................... 171 R EVIEW OF ETS’ S A NALYSIS FOR C ONTAINER G LASS M ELTING F URNACES ................................................ 174 R EFERENCES FOR C ONTAINER G LASS M ELTING F URNACES .................................................................... 177APPENDIX O– SODIUM SILICATE FURNACE......................................................................... 178
P ROCESS D ESCRIPTION ................................................................................................................... 178 C URRENT E MISSION I NVENTORY ...................................................................................................... 178 C ONTROL T ECHNOLOGY ................................................................................................................. 178 P ROPOSED BARCT LEVEL AND E MISSION R EDUCTIONS ........................................................................ 179 C OST E FFECTIVENESS ..................................................................................................................... 179 R EVIEW OF ETS’ S A NALYSIS FOR S ODIUM S ILICATE F URNACE ................................................................ 181 R EFERENCES FOR S ODIUM S ILICATE F URNACE ..................................................................................... 182 APPENDIX P – METAL HEAT TREATING FURNACES >150 MMBTU/HR.................................. 183
P ROCESS D ESCRIPTION ................................................................................................................... 183 C URRENT E MISSION I NVENTORY ...................................................................................................... 183 C ONTROL T ECHNOLOGY ................................................................................................................. 183 P ROPOSED BARCT LEVEL AND E MISSION R EDUCTIONS ........................................................................ 184 C OST E FFECTIVENESS ..................................................................................................................... 184 R EVIEW OF ETS’ S A NALYSIS FOR M ETAL H EAT T REATING F URNACES >150 MMBTU/ HR .......................... 185 R EFERENCES FOR M ETAL H EAT T REATING F URNACES >150 MMBTU/ HR ............................................... 186 APPENDIX Q – NON-REFINERY, NON-ELECTR ICAL ELECTRCITY GENERATING FACILITY STATIONARY GAS TURBINES .............................................................................................. 187
P ROCESS D ESCRIPTION ................................................................................................................... 187 C URRENT E MISSION I NVENTORY ...................................................................................................... 187 C ONTROL T ECHNOLOGY ................................................................................................................. 188 P ROPOSED BARCT LEVEL AND E MISSION R EDUCTIONS ........................................................................ 189 C OST E FFECTIVENESS ..................................................................................................................... 190 R EVIEW OF ETS’ S A NALYSIS FOR M ETAL H EAT T REATING F URNACES ABOVE 150 MMBTU/ HR .................. 192 R EFERENCES FOR N ON -R EFINERY , N ON -E LECTRICAL E LECTRCITY GENERATING FACILITY S TATIONARY G AS T URBINES
............................................................................................................................... ..... 193 APPENDIX R – NON-REFINERY STATIONARY INTERNAL COMBUSTION ENGINES.................. 194
P ROCESS D ESCRIPTION ................................................................................................................... 194 C URRENT E MISSION I NVENTORY ...................................................................................................... 194 C ONTROL T ECHNOLOGY ................................................................................................................. 196 P ROPOSED BARCT LEVEL AND E MISSION R EDUCTIONS ........................................................................ 196 C OST E FFECTIVENESS ..................................................................................................................... 197 R EVIEW OF ETS’ S A NALYSIS FOR N ON -R EFINERY S TATIONARY I NTERNAL C OMBUSTION E NGINES ................. 199 R EFERENCES FOR N ON -R EFINERY S TATIONARY I NTERNAL C OMBUSTION E NGINES ...................................... 199 APPENDIX S – NON-REFINERYBOILERS >40 MMBTU/HR .................................................... 200 APPENDIX T – SURVEY QUESTIONNAIRES FOR NON-REFINERY SECTOR............................... 201PART III – RTC REDUCTION APPROACHES ........................................................................... 203 APPENDIX U – STAFF’S PROPOSAL AND CEQA ALTERNATIVES ............................................ 200
S TAFF P ROPOSAL U NDER C ONSIDERATION ......................................................................................... 200 T RADABLE /U SABLE AND N ON -T RADABLE /N ON -U SABLE F ACTORS IN R ULE 2002( F )(1)(B) AND (C) ............ 206 R EGIONAL NSR H OLDING A CCOUNT ................................................................................................. 207 APPENDIX V – 2011 AUDITED EMISSIONS OF 20 TONS PER DAY.......................................... 213 APPENDIX W – 2012 EMISSIONS FOR POWER GENERATING SECTOR................................... 220 APPENDIX X – PROPOSED CHANGES IN RULES 2002, 2005, 2011 AND 2012......................... 222
R ULE 2002

.......................................................................................................................... ....... 218 R ULE 2005

.......................................................................................................................... ....... 222 O THER A DMINISTRATIVE A MENDMENTS ............................................................................................ 223 APPENDIX Y – RTC HOLDINGS AS OF SEPTEMBER 22, 2015 ................................................. 238 APPENDIX Z – COMMENT LETTERS RECEIVED AND RESPONSES TO COMMENTS.................. 245

## List of Tables

TABLE EX. 1 - S UMMARY OF P ROPOSED BARCT (M AY 2015)............................................................................................. 3 T ABLE EX. 2 – S UMMARY 2023 RTC H OLDINGS AND 2023 E MISSIONS A FTER BARCT............................................................. 5 T ABLE EX. 3 - S UMMARY OF C OSTS AND C OST E FFECTIVENESS ............................................................................................. 6 T ABLE EX. 4 - S UMMARY OF P UBLIC P ROCESS ................................................................................................................... 8 T ABLE EX. 5 - L IST OF P ARTICIPANTS ............................................................................................................................ 10

T ABLE 1. 1 – A UDITED E MISSIONS , RTC H OLDINGS AND U NUSED RTC S FROM 2009-2013 ..................................................... 16

T ABLE 2. 1 - A NNUAL A VERAGE E MISSIONS ( TPD ) BY M AJOR S OURCE C ATEGORY (2023 B ASE Y EAR ) ...........................................18 T ABLE 2. 2 - T OP T EN R ANKING OF NO X E MISSIONS FROM H IGHEST TO L OWEST (2023 B ASE Y EAR ) ............................................19 TABLE 2. 3 - NO X A UDITED E MISSIONS (2011 C OMPLIANCE Y EAR ) .........................................................................................20 T ABLE 2. 4 - NO X E MISSIONS PER S OURCE C LASSIFICATION ....................................................................................................21

T ABLE 3. 1 - 2015 P ROPOSED BARCT L EVELS AND E MISSION R EDUCTIONS ..............................................................................23 T ABLE 3. 2 - C O -B ENEFITS OF E MISSION R EDUCTIONS FOR E NERGY E FFICIENCY P ROJECTS ............................................................24

TABLE 4. 1 – I NITIAL P ROPOSAL - BARCT L EVELS , C OSTS AND C OST E FFECTIVENESS - R EFINERY S ECTOR (D ECEMBER 2014) .............27 T ABLE 4. 2 – I NITIAL P ROPOSAL - BARCT L EVELS , C OSTS AND C OST E FFECTIVENESS - N ON -R EFINERY S ECTOR (D ECEMBER 2014) .....28 TABLE 4. 3 - S TAFF ’ S R EVISED R ECOMMENDATION FOR R EFINERY S ECTOR (M AY 2015) ..............................................................29 TABLE 4. 4 - S TAFF ’ S R ECOMMENDATION FOR N ON -R EFINERY S ECTOR (M AY 2015) ..................................................................30

TABLE 5. 1 - R EMAINING E MISSIONS FOR R EFINERY S ECTOR ....................................................................................................32 TABLE 5. 2 - R EMAINING E MISSIONS FOR N ON R EFINERY S ECTOR (M AY 2015) .........................................................................34 T ABLE 5. 3 - S TAFF P ROPOSAL - A FFECTED F ACILITIES AND P ERCENT S HAVE ...............................................................................37 TABLE 5. 4 - A LTERNATIVES FOR CEQA A NALYSIS .................................................................................................................37 T ABLE 5. 5 - L IST OF F ACILITIES AND I NVESTORS THAT WOULD HAVE RTC S R EDUCED ...................................................................38

T ABLE A. 1 - 2011 E MISSIONS FOR R EFINERY FCCU S ............................................................................................................55 T ABLE A. 2 – L IST OF L O TO X A PPLICATIONS .........................................................................................................................61 T ABLE A. 3 - C OSTS AND C OST E FFECTIVENESS FOR SCR S (D ECEMBER 2014) ............................................................................66 T ABLE A. 4 – C OMPARISON OF SCR C OSTS E STIMATED BY S TAFF AND NEC (D ECEMBER 2014) ....................................................66 T ABLE A. 5 – R EVISED C OSTS AND C OST E FFECTIVENESS FOR SCR S (M ARCH 2015) ....................................................................68 TABLE A. 6 - C OSTS AND C OST E FFECTIVENESS FOR NO X R EDUCTION A DDITIVES ........................................................................69 TABLE A. 7 - C OSTS AND C OST E FFECTIVENESS FOR L O TO X A PPLICATIONS (D ECEMBER 2014) .....................................................70 T ABLE A. 8 – R EVISED C OSTS AND C OST E FFECTIVENESS FOR L O TO X S CRUBBERS (M ARCH 2015) .................................................71 T ABLE A. 9 – P RESENT W ORTH V ALUES OF SCR S AND L O TO X/S CRUBBERS FOR FCCU S .........................................................72 T ABLE A. 10 – I NCREMENTAL C OST E FFECTIVENESS OF SCR S AND L O TO X S CRUBBERS FOR FCCU S (M ARCH 2015) .........................72

T ABLE B. 1– T EMPERATURE Z ONES AND NO X E MISSIONS OF G REAT S OUTHERN F LAMELESS H EATER .............................................81 T ABLE B. 2 – P REDICTED P ERFORMANCE OF G REAT S OUTHERN O XY -F LAMELESS H EATER ............................................................82 T ABLE B. 3 – C OSTS OF SCR S E STIMATED B ASED ON I NFORMATION S UBMITTED BY R EFINERY ......................................................84 TABLE B. 4 – P ERFORMANCE AND C OST I NFORMATION OF SCR S FOR P ROCESS H EATERS FROM R EFINERY S URVEY ...........................85 TABLE B. 5 - C OSTS OF SCR S E STIMATED B ASED ON I NFORMATION FROM SCR M ANUFACTURERS ................................................87 TABLE B. 6 – C OSTS FOR G REAT S OUTHERN F LAMELESS H EATERS ............................................................................................87 T ABLE B. 7 - C OSTS FOR G REAT S OUTHERN F LAMELESS H EATERS WITH F UEL S AVINGS .................................................................87 T ABLE B. 8 - C OSTS FOR DUPLEX B URNERS .........................................................................................................................88T ABLE B. 9 - C OMPARISON OF NEC’ S AND S TAFF ’ S C OST E STIMATES FOR SCR S (D ECEMBER 2014) ..............................................91 TABLE B. 10 – R EVISED C OST E STIMATES OF SCR S FOR B OILERS AND H EATERS ..........................................................................92 TABLE B. 11 – D ETAILS OF C OST E STIMATES FOR B OILERS AND H EATERS ...................................................................................93

TABLE C. 1 - 2011 E MISSIONS FOR R EFINERY G AS T URBINES /D UCT B URNERS .........................................................................100 TABLE C. 2 – P ERFORMANCE OF DLN AND DLE ..................................................................................................................101 TABLE C. 3 – I NSTALLATIONS OF CLN

............................................................................................................................... .103 T ABLE C. 4 – C OSTS OF SCR AND ASC FOR 83 MW AND 7 MW C OGENERATION U NITS ...........................................................107 T ABLE C. 5 - P ROJECTED I NCOME G AIN D UE TO P OWER I NCREASE FOR C HENG L OW NO X .........................................................108 T ABLE C. 6 - E QUIPMENT AND I NSTALLATION C OSTS FOR C HENG L OW NO X ............................................................................109 T ABLE C. 7 – P RESENT W ORTH V ALUES AND C OST E FFECTIVENESS FOR G AS T URBINES ..............................................................110 T ABLE C. 8 - C OMPARISON OF S TAFF ’ S AND NEC’ S E STIMATES FOR G AS T URBINES ...................................................................112

T ABLE D. 1 - 2011 E MISSIONS FOR C OKE C ALCINER ............................................................................................................116 TABLE D. 2 – C OSTS OF L O TO X AND U LTRA C AT FOR C OKE C ALCINER (D ECEMBER 2014) ..........................................................120 T ABLE D. 3 - C OST AND C OST E FFECTIVENESS E STIMATES FOR C OKE C ALCINER (D ECEMBER 2014) ..............................................120 TABLE D. 4 – R EVISED C OST AND C OST E FFECTIVENESS E STIMATES FOR C OKE C ALCINER (M ARCH 2015) .....................................121

TABLE E. 1 - 2011 E MISSIONS FOR SRU/TG I NCINERATORS .................................................................................................124 TABLE E. 2 - L IST OF D YNA W AVE S CRUBBER I NSTALLATIONS FOR SR/TGTU S ..........................................................................127 TABLE E. 3 - P ROCESS I NFORMATION AND NO X E MISSIONS FOR SRU/TG I NCINERATORS IN SCAQMD ......................................130 TABLE E. 4 – NO X AND SO X P ERFORMANCE OF SRU/TG A PPLICATIONS IN SCAQMD ............................................................130 T ABLE E. 5 – C OST I NFORMATION P ROVIDED BY MECS .......................................................................................................132 TABLE E. 6 – C OST I NFORMATION P ROVIDED BY K NOW NO X ................................................................................................132 T ABLE E. 7 - C OMPARISON OF SCR C OSTS E STIMATED BY S TAFF AND NEC FOR SRU/TGTU S (D ECEMBER 2014) .........................133 TABLE E. 8 - R EVISED C OST AND C OST E FFECTIVENESS E STIMATES FOR SCR S AND L O TO X FOR SRU/TGTU S (M ARCH 2015) .........133

T ABLE K. 1- S UMMARY OF E MISSION R EDUCTIONS AND S CHEDULES OF E NERGY E FFICIENCY P ROJECTS .........................................156

T ABLE M. 1 - 2011 E MISSIONS FOR C EMENT K ILNS .............................................................................................................161 TABLE M. 2 - C OST E FFECTIVENESS FOR C EMENT K ILNS ........................................................................................................166 T ABLE M. 3 - ETS R EVISIONS TO C OST E FFECTIVENESS FOR C EMENT K ILNS ..............................................................................167 TABLE M. 4 - SCAQMD R EVISIONS TO C OST E FFECTIVENESS FOR C EMENT K ILNS .....................................................................168

T ABLE N. 1 - 2011 E MISSIONS FOR C ONTAINER G LASS M ELTING F URNACES ............................................................................170 T ABLE N. 2 - C OST E FFECTIVENESS FOR C ONTAINER G LASS M ELTING F URNACES .......................................................................173 TABLE N. 3 - ETS R EVISIONS TO C OST E FFECTIVENESS FOR C ONTAINER G LASS M ELTING F URNACES .............................................176

TABLE O. 1 - 2011 E MISSIONS FOR S ODIUM S ILICATE F URNACE ............................................................................................178 T ABLE O. 2 - C OST E FFECTIVENESS FOR S ODIUM S ILICATE F URNACE .......................................................................................180 T ABLE O. 3 - ETS R EVISIONS TO C OST E FFECTIVENESS FOR S ODIUM S ILICATE F URNACE .............................................................181

TABLE P. 1 - 2011 E MISSIONS FOR M ETAL H EAT T REATING F URNACES >150 MMBTU/ HR ......................................................183 TABLE P. 2 - C OST E FFECTIVENESS FOR F URNACES > 150 MMBTU/ HR ..................................................................................185

TABLE Q. 1 - 2011 E MISSIONS FOR RECLAIM N ON -E LECTRICAL E LECTRCITY GENERATING FACILITY G AS T URBINES .......................188 T ABLE Q. 2 - C OST E FFECTIVENESS FOR N ON -E LECTRICAL E LECTRCITY GENERATING FACILITY G AS T URBINES ..................................191T ABLE R. 1 - 2011 E MISSIONS FOR I NTERNAL C OMBUSTION E NGINES AT T OP 37 F ACILITIES ......................................................195 TABLE R. 2 - C OST E FFECTIVENESS FOR L EAN -B URN , N ON -OCS ICE S .....................................................................................198

T ABLE S. 1 - C OST E FFECTIVENESS FOR N ON -R EFINERY B OILERS >40 MMBTU/ HR ..................................................................200

TABLE V. 1 - 2011 A UDITED E MISSIONS ............................................................................................................................213

T ABLE W. 1 - C OMPLIANCE Y EAR 2011 P OWER G ENERATING S ECTOR E MISSIONS ....................................................................220 T ABLE W. 2 - 2012 P OWER G ENERATING S ECTOR E MISSIONS B ASED ON A NNUAL E MISSION R EPORTS (AER) F UEL U SAGE ............221

## List of Figures

F IGURE EX. 1 – A UDITED E MISSIONS AND RTC H OLDINGS ........................................................................................................4 F IGURE 1. 2 – A UDITED E MISSIONS AND RTC H OLDINGS ........................................................................................................14 F IGURE 1.3 – NO X D ISCRETE RTC P RICE VERSUS T HRESHOLD .................................................................................................15 F IGURE 1.4 – NO X I NFINITE Y EAR B LOCK (IYB) RTC P RICE VERSUS T HRESHOLD ........................................................................15 F IGURE 1. 5 – D ISTRIBUTION OF 20 TPD NO X E MISSIONS (E ND OF C OMPLIANCE Y EAR 2011) .....................................................17 F IGURE 1. 6 – D ISTRIBUTION OF 26.5 TPD RTC H OLDINGS (E ND OF C OMPLIANCE Y EAR 2020) ....................................................17

F IGURE A. 1 - S IMPLIFIED S CHEMATIC OF FCCU P ROCESS .......................................................................................................54 F IGURE A. 2 - 2011 NO X E MISSIONS AND NO X C ONCENTRATIONS FOR R EFINERY FCCU S ..........................................................56 F IGURE A. 3 - 2011 NO X E MISSIONS AND F EED R ATES FOR R EFINERY FCCU S ...........................................................................56 F IGURE A. 4 - EDV S CRUBBER WITH L O TO X A PPLICATION ......................................................................................................60 F IGURE A. 5 - N ITROGEN C HEMISTRY IN THE FCC R EGENERATOR .............................................................................................63 F IGURE A. 6 - NO X R EDUCTION A DDITIVE R EDUCES NO X E MISSIONS BY 60% ...........................................................................63

F IGURE B. 1 - R EFINERY P ROCESSES

............................................................................................................................... .....77 F IGURE B. 2 - O XY -F LAMELESS H EATER (R EFERENCE 17) ........................................................................................................81 F IGURE B. 3 – R EVISED PWV S OF C ONTROL D EVICES FOR R EFINERY B OILERS/H EATERS (M ARCH 2015) .......................................89

F IGURE C. 1 - G AS T URBINE WITH D UCT B URNER ( VICTORYENERGY . COM ) .................................................................................98 F IGURE C. 2 - C HENG L OW NO X (R EFERENCE 22) ...............................................................................................................102 F IGURE C. 3 - E FFECT OF H OMOGENEITY AND S TEAM TO F UEL R ATIO IN CLN A PPLICATION (R EFERENCE 22) ................................103 F IGURE C. 4 - E FFECT OF H OMOGENEITY AND S TEAM TO F UEL R ATIO ON NO X E MISSIONS IN CLN A PPLICATION ...........................104 F IGURE C. 5 - P RESENT W ORTH V ALUES FOR G AS T URBINES .................................................................................................109

F IGURE D. 1 - C OKE C ALCINER P ROCESS (R EFERENCE 1) .......................................................................................................117 F IGURE D. 2 - U LTRA -C AT F ILTERS (R EFERENCE 5) ...............................................................................................................118

F IGURE E. 1 - D YNA W AVE S CRUBBER (R EFERENCE 23) ........................................................................................................126 F IGURE E. 2 - O ZONE G ENERATION P ROCESS (R EFERENCE 23) ...............................................................................................126 F IGURE E. 3 – K NOW NO X P ROCESS (R EFERENCE 28) ..........................................................................................................128

F IGURE M. 1 - U LTRA C AT C ERAMIC F ILTER S YSTEM ............................................................................................................163 F IGURE M. 2 - C LOSE -U P OF F ILTER H OUSING AND S YSTEM O PERATION (R EFERNCE #2) ...........................................................163

F IGURE Q. 1 - NO X C ONCENTRATIONS FOR N ON -E LECTRICAL E LECTRCITY GENERATING FACILITY G AS T URBINES AT T OP 37 E MITTING F ACILITIES

............................................................................................................................... ............................188

F IGURE R. 1 - NO X CONCENTRATIONS FOR L EAN B URN ICE S AT T OP 37 E MITTING F ACILITIES ....................................................195AC AER AQMP ASC Basin BACT BARCT CARB CE CEMS CLN TM CM CO CO 2 CR CY DCF DLN/DLE DOE EPA ER ESP ETS

o F FCCU GF HHV HRSG H&SC GFIYB LCF LoTOx TM NAAQS NEC NO NO 2 N 2 O NOx OCS OAQPS PAR ppm PWV RACM RACT RECLAIM 

## List of Acronyms
Annual Operating Cost Annual Emissions Report Air Quality Management Plan Ammonia Slip Catalyst South Coast Air Basin Best Available Control Technology Best Available Retrof it Control Technology California Air Resources Board Cost Effectiveness Continuous Emissions Monitoring System Cheng Low NOx Control Technology Control Measure Carbon Monoxide Carbon Dioxide Catalyst Replacement Compliance Year Discounted Cash Flow Method Dry Low NOx/Dry Low Emissions U.S. Department of Energy U.S. Environmental Protection Agency Emission Reductions Electrostatic Precipitator Environmental Technology Services Degree Fahrenheit Fluid Catalytic Cracking Unit Growth Factor High Heating Value of Fuel Heat Recovery Steam Generator Health & Safety Codes Growth FactorInfinite Year Block Levelized Cash Flow Method Low Temperature Oxidation Process for NOx Control National Ambient Air Quality Standards Norton Engineering Consultants Nitric Oxide Nitrogen Dioxide Nitrous Oxide Nitrogen Oxides Outer Continental Shelf Office of Air Quality Planning and Standards Proposed Amended Rule or Proposed Amended Regulation Parts Per Million Present Worth Values Reasonably Achievable Control Measure Reasonably Achievable Control Technology Regional Clean Air Incentive Market ProgramRTC RECLAIM Trading Credit SCAQMD South Coast Air Quality Management District SCR Selective Catalytic Reduction SIP State Implementation Plan SNCR Selective Non Catalytic Reduction SO 2 Sulfur Dioxide SO 3 Sulfur Trioxide SOx Sulfur Oxides SRU/TG Refinery’s Sulfur Recovery Unit /Tail Gas Treating Unit TIC Total Installed Costs tpd or TPD Tons Per Day Ultra-CatTM Ultra-Cat Catalyst Filter Manufactured by Tri-Mer Corporation WHB Waste Heat Boiler WGM Working Group Meeting WSPA Western States Petroleum Association

### 1 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Executive Summary
Background
On October 15, 1993, the South Coast Air Quality Management District (SCAQMD) Governing Board adopted Regulation XX - REgional Clean Ai r Incentives Market (RECLAIM). Regulation XX includes rules that specify the applicability and procedures for determining NOx and SOx facility emissions allocations, program requirements, as well as monitoring, reporting, and recordkeeping requirements for sources located at RECLAIM facilities. RECLAIM was designed to provide equivalent emission reduction in the aggregate for the facilities in the program compared to what would occur under a command-and-control approach, with flexibility for each facility to find the most cost-effective strategy to meet their emission reduction targets. The program requires robust monitoring to ensure compliance. Over the past more than 20 years, the program has resulted in significant emission re ductions. The RECLAIM program started with 392 NOx facilities in 1993. By the end of complianc e year 2013, there were 275 facilities in the NOx RECLAIM universe.

Best Available Retrofit Co ntrol Technology for RECLAIM When the NOx RECLAIM program was first adopted, the NOx RECLAIM facilities were issued NOx annual allocations (also know n as facility caps), which declined annually from 1993 until 2003 and remained constant after 2003. The annual allocations issued to the NOx RECLAIM facilities reflected the levels of Best Available Retrofit Contro l Technology (BARCT) envisioned to be in place at the RECLAIM facilities, and we re the result of a BARCT analysis conducted in 1993. A BARCT reassessment is required by the California Health & Safety Code (H&SC) §40440 to assess the advancement in control tech nology and to ensure that RECLAIM facilities achieve the same emission reduc tions that would have occurr ed under a command-and-control approach and that emission reductions from the progr am contribute to the efforts in the Basin to achieve the federal National Ambient Air Quality Standards (NAAQS). The SCAQMD staff conducted a BARCT reassessment for NOx in 2005 and another for SOx in2010, and subsequently amended the RECLAIM rules to reduce the facility annual allocations. RECLAIM facilities have the flexibility to install air pollution control equipment, change their operations, or purchase RECLAIM Trading Credits (RTCs).

Ozone Non-Attainment Status On March 12, 2008, the EPA strengthened its gro und-level 8-hour ozone st andard from 0.08 parts per million (ppm) to 0.075 ppm. On May 21, 2012, the EPA classified two areas in the country, the South Coast and the San Joaquin Valley, as “Extreme” non-attainment areas with respect to the 2008 8-hour ozone standard. The attainment dates for the 1997 and 2008 ozone standards are

### 2 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 June 15, 2024 and July 20, 2032, respectively with emissions reductions and attainment required in the previous calendar year. NOx is a precursor for ozone. Significant reductions in NOx emissions are necessary for the Basin to attain the federal 24-hour PM2.5 standard in by 2019 and the federal ozone ambient air quality standards in 2023 and 2031.
2012 Air Quality Management Plan and Control Measure CMB-01 The SCAQMD developed and adopted the 2012 Air Quality Management Plan (AQMP) in partnership with CARB, U.S. EPA, SCAG and st akeholders throughout the region to outline the strategy to meet and maintain the state and federal air quality standards. The 2012 AQMP identified control measures needed to attain the federal 24-hour standard for PM2.5 by 2014 and provided updates on progress towards meeting the 8-hour ozone standard in 2023. Control Measure CMB-01 – Further NOx Reduction for RECLAI M is one of the control measures included in the 2012 AQMP. Control Measure CMB-01 ca lled for a reassessment of BARCT for NOx RECLAIM facilities and estimated that a total of 2-3 tons per day (tpd) of NOx emission reductions could be achieved in 2014 for Phase I with an additional of 1-2 tpd NOx in 2020 for Phase II following the BARCT analysis. CMB-01 Phase I served as a PM2.5 SIP contingency measure for the 2012 AQMP, and if emission reductions were not needed in Phase I, the RTC reductions estimated for Phase I would be combined with the total reductions that could be achieved in Phase II. It was anticipated that NOx emissions reduc tions from both phases would also contribute to meeting the ozone standards in 2024 and 2032.
Current Emissions and RTC Holdings

The 2011 audited actual emissions were 20 tons per day (tpd) for the RECLAIM universe (59% from the refineries and 41% from the non-refinerysector). For electri cal electricity generating facilities, staff used 2012 emissions instead of 2011 due to several reasons: 1) local electrical electricity generating facilities in the region operate d more in 2012 to make up for the closure of the San Onofre Nuclear Generation Station (SO NGS), 2) the commissioning of new electrical electricity generating facilities in the region was re flected more accurately in 2012, and 3) a recent shift in the use of renewable energy sources, suchas wind, solar, and water, and their inherent intermittency resulted in the use of peaking units with increased numbers of startups and associated emissions. The 2011/2012 baseline emissions for th e NOx RECLAIM universe in this analysis were 20.7 tpd. The RECLAIM Trading Credit (RTC) holdings for the RECLAIM universe were 26.5 tpd, of which the refinery sector held 51% of the RTCs, electrical electricity generating facilities 21%, investors 4% and other RECLAIM facilities 24%.

### 3 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Proposed BARCT, Emission Reductions, and RTC Reductions
The BARCT analysis resulted in the BARCT leve ls and incremental emission reductions by 2023 shown in Table EX.1. For the refinery sector, a ne w level of BARCT is proposed for fluid catalytic cracking units, boilers/heaters >40 mmbtu/hr, gas turbines, coke calciners, and sulfur recovery and tail gas incinerators. For the non-refinery sector , a new BARCT level is proposed for container glass melting furnaces, cement kilns, sodium silicate furnaces, metal melting furnaces >150 mmbtu/hr, gas turbines and ICEs not located on the outer continental shelf (OCS). No new BARCT is proposed for electrical electricity generating facilities. 1
Table EX. 1 - Summary of Proposed BARCT (May 2015)

Incremental Emission Refinery Sector 2015 BARCT Level Reductions from 2000/2005 BARCT (tpd) Fluid Catalytic Cracking Units 2 ppmv at 3% O2 0.43 Refinery Boilers and Heaters >40 mmbtu/hr 2 ppmv or 0.002 lb/mmbtu 0.94 Refinery Gas Turbines 2 ppm at 15% O2 4.14 Coke Calciner 10 ppmv at 3% O2 0.17 Sulfur Recovery Units Tail Gas Incinerators 2 ppmv at 3% O2 or 95% reduction 0.32 Total 6.00 Incremental Emission Non-refinery Sector 2015 BARCT Level Reductions from 2000/2005 BARCT (tpd) Container Glass Melting Furnaces 80% reduction 0.24 Sodium Silicate Furnace 80% reduction 0.09 Metal Heat Treating Furnaces >1 50 mmbtu/hr 9 ppmv at 3% O2 0.56 Gas Turbines (non-OCS) 2 ppmv at 15% O2 1.04 Internal Combustion Engines (non-OCS) 11 ppmv at 15% O2 0.84 Cement Kilns 0.5 lbs/ton 1.29 (note) Total 2.77 Note: The 1.29 tpd emission reductions from cement kilns were not included in the 2.77 tpd emission reductions because the ceme nt facility was not in operation in 2011. Cement kilns were the highest emitting stationary source of NOx emissions in 2008, thus staff co nducted a BARCT analysis for cement kilns and reduced the remaining emissions projected to the 2023 level for the cement facility to the BARCT level.

1 Staff conducted a BARCT analysis focusing on the top 37 NOx emitting facilities in 2011, and a cement plant which was the highest NOx emitting stationary source in 2008. The BARCT analys es with detailed information are in the appendices (Appendices A-J of Part I for the refinery sector, and Appendices M-S of Part II for the non-refinery sector.)

### 4 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 As shown in Table EX.1, the total BARCT-equiva lent emission reductions are 8.8 tpd (6.00 tpd for the refinery sector and 2.77 tpd for the non-re finery sector.) Due to projected growth, 2 the remaining emissions in 2023 at these proposed2015 BARCT levels would be 10.2 tpd (2.76 tpd for the refinery sector and 7.47 tpd for the non-refi nery sector.) Staff has added a 10% compliance margin to the 2023 remaining emissions. In a ddition, staff has added th e remaining emissions from shutdown glass and cement facilities at BARCT levels, thereby adding to the compliance margin, as well as the emissions for new fac ilities entering RECLAIM program since 2005 to the total remaining emissions. Sta ff has provided some adjustments to account for uncertainties that arose in the BARCT analysis and for additional 2011 activity level adjustment. This results in total proposed NOx RTC reductions of 14 tpd fro m the current RTC holdings of 26.5 tpd in 2023. 3 The remaining RTCs for the NOx RECLAIM universe would be 12.5 tpd (26.5 tpd – 14 tpd = 12.5 tpd), which is 2.3 tpd or almo st 2322.5% above the projected re maining emissions from RECLAIM NOx sources in 2023. See Figure EX.1.

26.5

20.7
18.3

10.2

0 5 10 15 20 25 30Tons Per Day

above emissions at 2015 BARCT 14 tpd Shave

12.5

9.5 8.8 tpd BARCT

Reductions

2.3 tpd 22.5%

Allocation 2011/2012 2011 Emissions at 2011 Emissions at 2023 Emissions 2023 Remaining Emissions 2000/2005 BARCT 2015 BARCT at 2015 BARCT RTCs

Figure EX. 1 – Audited Emi ssions and RTC Holdings

2 The growth factor for the refineries is 1. Electric generating fa cilities are expected to be more efficient with growth factor o f 0.89 (2014 California Gas Report). The average growth factor for other non-refinery facilities is 1.1 (Southern California Associati on of Government (SCAG)).

3 RTC Reductions = RTC Holdings – Remaining Emissions in 2023 - Adjustments = 14 tpd. Refer to Chapter 5 and Appendix U of Part III for detailed information.

### 5 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Staff is proposing to distribute the 14 tpd NOx RT C reductions to 56 facilitie s and investors that hold 90% of the 26.5 tpd RTCs. Investors are groupe d with the refineries and treated as a facility for shave purposes. The remaining 219 facilitie s that hold 10% of the 26.5 tpd RTC are not proposed to be shaved because there was limited or no new BARCT for the types of equipment and operation at these facilities. 4 Staff’s current proposal is to weight the amount of shave considering the technology available to diff erent facility types as summarized below:

66% shave for 9 refineries and investors 49% shave for 21 electrical electricity generating facilities 49% shave for 26 other major facilities 0% shave for 219 remaining facilities The 2023 remaining emissions after installing BARCT , the RTC holdings after the shave, and the surplus or deficit RTCs after the shave for each industry sector are presented in Table EX.2. After the shave, the 9 refineries, the investors, and the 21 electrical electricity generating facilities would have surplus RTCs. Some facilities in the 26 non- electrical electri city generating facilities and the 219 remaining facilities would not be subject to any shave however their emissions would grow above the RTC holdings that they currently have and they would have to purchase RTCs from other industry sectors to reconciletheir projected emissions. Overall, there is a net of 2.3 tpd surplus RTCs for the entire RECLAIM universe.
Table EX. 2 – Summary of 2023 RTC Holdings and 2023 Emissions After BARCT 9 15 21 26 Non- 219 Other Net Refineries Investors Electrical Electrical Facilities Total Electricity Electricity generating generating

facilities facilities Current RTC Holdings (tpd) (note) 14.15 0.42 5.63 3.45 2.86 26.5 % Shave 66% 66% 49% 49% 0% RTC Holdings After Shave (tpd) 4.81 0.14 2.87 1.76 2.86 12.5 2023 Emissions After BARCT (tpd) 2.76 0 2.04 1.93 3.5 10.2 Surplus or Deficit RTCs (tpd) 2.05 0.14 0.83 (0.17) (0.64) 2.3 Note: RTC Holdings as of September 22, 2015 Staff is proposing to implement the 14 tpd RTC reductions over a 7-year period from 2016 to 2022 but as expeditiously as possible to help the Basi n meet the PM2.5 standard deadlines as well as the ozone standards in 2023 and 2031. Staff is proposing the followi ng implementation schedule for NOx RTC reductions: 2016 – 4 tons per day

4 The ICEs and small boilers or heaters in the remaining 21 9 facilities could be subject to additional BARCT but the potential emission reductions totaled less than 0.1 tpd.

### 6 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 2018 – 2 tons per day 2019 – 2 tons per day 2020 – 2 tons per day 2021 – 2 tons per day 2022 – 2 tons per day Over the past five years from 2009-2013, the unused RTCs in the NO x RECLAIM program ranged from 5 tpd to 8 tpd. Staff is proposing a 4 tpd RTC reduction in 2016. Additional BARCT implementation will ta ke about 2 - 4 years for planning, permitting, and cons truction, and thus staff is proposing the remaining shave of 10 tpd to take place over five years from 2018 to 2022. The BARCT analyses are described in Chapter 3, the costs and cost effectiveness of the proposal are described in Chapter 4 and are summarized inTable EX.3. The total Present Worth Values (PWVs) of the project range from $728 M to $1.1 B, and the overall cost e ffectiveness values of the project as a whole range from $9 K to $14 K per ton NOx reduced. Individual category costeffectiveness is set forth in the table below. The RTC reductions are estimated in Chapter 5, and the proposed changes in rule language are described in Chapter 6.
Table EX. 3 - Summary of Costs and Cost Effectiveness

2015 BARCT Incremental Emission Reductions from 2000/2005 BARCT

(t p d) Number of Affected Facilities Estimated No of Control

Devices PWVs ($M) Incremental Cost Effectiveness

(thousand dollars/ton) Refinery Sector FCCUs 2 ppmv 0.43 5 5 SCRs (or 2 SCRs + 3 LoTOx/WGS) 152 - 391 3 - 13 Boilers and Heaters 2 ppmv 0.94 8 75 73 SCRs 237 28 Refinery Gas Turbines 2 ppm 4.14 5 7 SCRs and adding catalysts to 4 SCRs 53 - 98 1 - 3
Coke Calciner 10 ppmv 0.17 1 1 UltraCat (or 1 LoTOx/WGS) 40 - 91 22 - 35
SRU/TG Incinerators 2 ppmv 0.32 4 6 SCRs (or 1 SCRs + 5 LoTOx/WGS) 83 - 106 28 - 40

Refinery Total 6.00 92 91 SCRs + 1 UltraCat (or 84 83 SCRs and 9 LoTOx/WGS) and adding catalysts to SCRs 565

- 923 10 - 17

Non-Refinery Sector Glass Melting Furnaces 80% red 0.24 1 2 SCRs (or 1 UltraCat) 6 - 15 3 - 7 Sodium Silicate Furnace 80% red 0.09 1 1 SCR (or 1 UltraCat) 3 - 5 4 - 8 Metal Heat Treating 9 ppmv 0.56 1 1 SCR 8 - 10 3 - 4 Gas Turbines (non-OCS) 2 ppmv 1.04 3 14 SCRs ~109 5 - 36 ICEs (non-OCS) 11 ppmv 0.84 7 16 SCRs ~37 5 - 8

### 7 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Non-Refinery Total (w/o Cement Kilns) 2.77 34 SCRs (or 31 SCRs and 2 UltraCat) 163 - 176 6 - 7

Overall 8.8 127 125 SCRs + 1 UltraCat (or 115 114 SCRs + 9 LoTOx/WGS + 2 UltraCat) 728 - 1099 9 - 14



## Public Process
The public process for PAR XX – NOx RECLAIM is summarized in Table EX.4. Staff began this rulemaking process in the 4 th quarter 2012. In 2013, staff formed a RECLAIM Working Group to discuss potential amendments to th e NOx RECLAIM program that included members representing NOx RECLAIM facilities, the Western States Petroleum Association (WSPA), the environmental community, as well as CARB and U.S. EPA. Th e first meeting was conducted on January 31, 2013. A list of particip ants is shown in Table EX.5. To gather pertinent information for rule development, staff sentout Survey Questionnaires to 38 facilities, including the top 37 emitting facilities in 2011 and a ce ment facility which was the highest NOx stationary emission sour ces in 2008. Since January 2013, eleven fourteen Working Group Meetings were held to discuss potential BA RCT levels for major NOx sources at the top 37 and cement facilities, the emissions inventory, potential for emission reductions, and proposals for RTC reductions. 5 In addition, in September 2014, SCAQM D staff contracted with two consultants (Environmental T echnology Services, Inc. (ETS) and Norton Engineering Consultants Inc. (NEC)) to conduct independen t BARCT analyses. The consultants and staff visited a glass manufacturing facility, a cement manufacturing facility, and six refineries to assess the availability of space for the installation of additional controls and to discuss BARCT issues and concerns with the stakeholders. The cons ultants completed their analyses in December 2014, and staff held the 8 th Working Group Meeting in January 7, 2015 to report on the consultants’ findings to the stakeholders. A CEQA and Socio economic scoping session was held in January 8, 2015 and staff received ten comment letters. Fr om January to March 2015, staff reviewed the consultants’ analyses and addressed comments received inresponse to the CEQA and Socioeconomic scoping session. Staff also exte nded the contract for NEC to allow time to produce the confidential proprietary information reports for each refinery, and this task was completed in April 2015. In addition to the twelve fourteen Working Group Meetings, staff participated in over 30 50 meetings held with various stakeholders individually or in groups to discuss the BARCT analysis and the proposed allocation reduction distribution (shave) methodology. Staff also met with a

5 The Survey Questionnaires for the refineries and non-refineries are in Appendix L and Appendix T, respectively. The detailed BARCT analyses are in the relevant appendices (Appendices A-J for refinery sector and Appendices M-S for non-refinery sector.) Staff focused on the top 37 emitting facilities contributing more th an 85% of the 2011 em issions and the cement plant which was the highest NOx stationary emission source in 2008. Staff looked at other sources in the remaining facilities: the emission reductions from ICEs and small boilers and heaters at these facilities would gene rate less than 0.1 tpd emission reductions andstaff did not identify any more stringent BARCT for other equipment at these facilities.

### 8 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 number of air pollution control manufacturers to discuss control technolog ies, and invited the manufacturers to write manuscripts and give presentations at th e 2014 Air & Waste Management Association annual conference in Long Beach. Several refinery representatives participated in the discussions at the conference. A Public Workshop was conducted on July 22 , 2015, a Public Consultation Meeting was conducted on September 29, 2015, the draft Program Environmental Assessment was released on August 1314, 2015 for 75 days public comments, and the draft socioeconomic analysis was released on September 9, 2015. Three Four Stationary Source Committee mee tings were held on March 21, 2014, July 24, 2014, and October 14, 2015, and November 20, 2015 including a special session requested by industry devoted to RECLAI M discussion. The Public Hearing is scheduled for November 6December 4, 2015.
Table EX. 4 - Summary of Public Process

Calendar Year 2013 January 31, 2013 RECLAIM Working Group was formed. The 1 st RECLAIM Working Group Meeting was conducted March 20, 2013 2 nd RECLAIM Working Group Meeting

June 13, 2013 3 rd RECLAIM Working Group Meeting. Staff conducted a Survey to gather information for rule development. September 19, 2013 4 th RECLAIM Working Group Meeting Calendar Year 2014 January 22, 2014 5 th RECLAIM Working Group Meeting March 18, 2014 6 th RECLAIM Working Group Meeting March 21, 2014 1 st Stationary Source Committee Meeting

July 31, 2014 7 th RECLAIM Working Group Meeting September 2014 –

December 2014 Staff contracted ETS and NEC to conduct independent BARCT analyses for the non-refinery and re finery sectors. The consultants and staff visited facilities to discuss BARCT issues with the stakeholders and assess space availability. The consultants finalized their analyses and reports in December 2014. Calendar Year 2015 January 7, 2015 8 th RECLAIM Working Group Meeting. Staff presented the results of the consultants’ analyses to the Working Group Meeting. January 8, 2015 A CEQA and Socioeconomic Scoping session was held. Ten (10) comment letters were received. January – March Staff conducted a review of the consultants’ analyses and addressed the comments received in the CEQA and Socioeconomic Scoping sessions.

### 9 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
April 10, 2015 The contract for NEC was exte nded to separate co nfidential reports for the refineries. This task was completed April 10, 2015 April 29, 2015 9 th RECLAIM Working Group Meeting

June 4, 2015 10 th RECLAIM Working Group Meeting July 9, 2015 11 th RECLAIM Working Group Meeting July 22, 2015 Public Workshop. Release Pr eliminary Draft Staff Report and Rule Language July 24, 2015 2 nd Stationary Source Committee Meeting August 1314, 2015 Release Draft Program E nvironmental Assessment. Draft PEA commenting period extended to October 6, 2015 September 9, 2015 Release Draft Socioeconomic Report September 23, 2015 3 rd Stationary Source Committee Meeting 12 th RECLAIM Working Group Meeting September 29, 2015 Public Consultation Meeting

October 14, 2015 3 rd 4th Stationary Source Committee Meeting November 20, 2015 5 th Stationary Source Committee Meeting November 23, 2015 13 th RECLAIM Working Group Meeting November 30, 2015 14 th RECLAIM Working Group Meeting November 6December 4, 2015 Public Hearing

### 10 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table EX. 5 - List of Participants Organizations California Council for Environmental and Economic Balance (CCEEB) Earth Justice Industry Coalition Regulatory Flexibility Group (RegFlex) Southern California Air Quality Alliance (SCAQA) Western States Petroleum Association

Facilities Air Products California Portland Cement Company Chevron ExxonMobil Owens Brockway Paramount Phillips66 Tesoro Ultramar Other facilities

Manufacturers of Control Devices & Consultants BASF BELCO Cheng Low NOx ClearSign Cormetech ETS Elex CEMCAT Grace Davidson Great Southern Flameless Haldor Topsoe INTERCAT MECS Mitsubishi NEC Tri-Mer

Others California Air Resources Board California Indepe ndent System Operator (CalISO

### 11 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Bay Area Air Quality Management District Santa Barbara Air Pollu tion Control District San Joaquin Valley Air Pollution Control District U.S. Environmental Protection Agency

### 12 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Chapter 1 – Background Legislative Authority
The California Legislature created the SCAQMD in 1977 as the agency responsible for developing and enforcing air pollution control rules and regulati ons in the South Coast Air Basin (Basin). The H&SC requires the SCAQMD to adopt an AQMP outlining how the Basin will achieve and maintain state and federal ambient air quality standards by the earliest practicable date. In addition, the SCAQMD is required to adopt rules and regulations to implement the AQMP. The SCAQMD’s rules and regulations must contain BA RCT for existing sources. The SCAQMD staff is required to conduct a BARCT reassessment on a regular basis to capture the advancement in control technology and to ensure that RECLAIM facilities achieve the e mission reductions that would have occurred under a command-and-contro l approach and that emission reductions from the program contribute to the Basin achieving the federal and state ambient air quality standards. The relevant H&S provisions, including a definition of BARCT, are cited below:
H&SC §40460(a): “ ... the south coast district board shall adopt a plan to achieve and maintain the state and federal ambient air quality standard. ”
H&SC §40440(a): “The south coast district board shall adopt rules and regulations that carry out the plan and are not in conflict with state law and federal laws and rules and regulations .”
H&SC §40440(b)(1): “ The rules and regulations adopted ... shall ... require the use of best available control technol ogy for new and modified sources and the use of best available retrofit control technology for existing sources .”
H&SC §40406: “... best available retrofit technology means an emi ssion limitation that is based on the maximum degree of reduction achievabl e taking into account environmental, energy, and economic impacts by each class or category of source. ” 

## Non-Attainment Status
Relative to the ozone and PM2.5 NAAQS promulgated by the U.S. EPA to protect public health and the environment, the Basin is currently classified as an “extreme” non-attainment area for ozone and is a non-attainment area for annual an d 24-hour PM2.5. Scientific studies have found an associations between exposure to particulate matter and ozone and signif icant health problems, including asthma, chronic bronchitis, reduced lung function, irregular hear tbeat, heart attack, and premature death in people with heart or lung di sease. Individuals particularly sensitive to air pollution exposure include older adults, people with heart and lung disease, and children.

### 13 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

There are six criteria pollutants that contribute to ambient air pollution for which there are federal NAAQS: ozone, carbon monoxide, lead, particulate matter, sulfur diox ide, and nitrogen dioxide. The effect of reducing emissions of each of these pollutants varies by area depending on the composition of the atmosphere, conc entrations of these pollutants an d other area-specific factors. The federal EPA requires the SCAQMD to implement all reasonably available control measures (RACM) and reasonably available control t echnology (RACT) considering economic and technical feasibility and other factors to reduce criteria air pollutants. On March 12, 2008, the EPA strengthened its gr ound-level 8-hour ozone standard from 0.08 ppm to a level of 0.075 ppm. On May 21, 2012, the EPA classified two areas in the country, the South Coast and the San Joaquin Valley, as “Extreme” non-attainment areas with respect to the 2008 8- hour ozone standard. The attainment dates for the 1997 and 2008 ozone standards are June 15, 2024 and July 20, 2032, respectively, with emissi on reductions and attain ment required in the previous calendar year. NOx is a major precu rsor of ozone and PM2.5, and reducing NOx is essential for the Basin to attain the ozone ambien t air quality standards while also helping to meet PM2.5 standards. The SCAQMD staff is currently developing the 2016 AQMP to address ozone and PM2.5 attainment strategies. 

## Control Measure CMB-01 of the 2012 AQMP

Control Measure CMB-01 – Further NOx Reductions from RECLAIM is one of the control measures specified in the 2012 AQMP. The control measure CMB-01 has 2 phases: Phase I has an estimated reduction of 2–3 tpd NOx and serves as a contingency measure for PM2.5 attainment. A contingency measure is a measure that will be automatically implemented if the basin fails to meet the PM2.5 standards by the attainment date. Based on recent data, the Basin will fail to meet the 24-hour PM2.5 ambient air quality standard by th e original attainment date of 2014 as well as the revised attainment date of 2015. Therefore, the SCAQMD has asked EPA to reclassify the Basin as “serious” non-attainment for the 24-hour st andard, and will be requ ired to submit a new attainment plan. If Phase I wa s not triggered, CMB-01 anticipated that Phase I reductions would be rolled into Phase II to help attain the ozone standards. In combination, Phase I and Phase II together had estimated reductions of 3-5 tpd with the lower end of emission reduction range committed to in the State Implementation Plan (SIP) yet to be acted on by U.S. EPA. The adoption date and implementati on date for Control Measure CMB- 01 were estimated to be 2015 and 2020, respectively. The analysis done for these amendm ents resulted in significantly more reductions than those identified in the control measure. The control measure emission reduction estimates are based on information available at that time , and the emission reductions proposed for a rule that implements a control measure can be more or less than the control measure estimate based on additional analysis of available cost effec tive technologies. The control measure CMB-01 mentioned that additional reductions would be sought if re quired to implement BARCT, and that all feasible reductions are needed to attain the ozone standards.

### 14 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015


## Current NOx RECLAIM Program
On October 15, 1993, the SCAQMD’s Governing Board adopted the RECLAIM program and Regulation XX. Regulation XX includes 11 rules that specify the applicability, NOx and SOx allocations, general requirement s, as well as monitoring, reporting, and recordkeeping requirements. The RECLAIM program starte d with 392 NOx facilities in 1993, dropped to 281 facilities in 2011, with 2 75 facilities by end of the 2013 comp liance year. Under the RECLAIM program, facilities are issued SOx and NOx annual allocations, also known as facility caps. The facility caps decline annually to reflect the levels of BARCT that were envisioned to be in place at the RECLAIM facilities. To meet their annual declining allocations, RECLAIM facilities have the flexibility of installing pollution control equipment, changing operations, or purchasing RECLAIM Trading Credits. It was envisioned that a BARCT analysis would be conducted periodically to capture the advancement in cont rol technology and to assure that the RECLAIM program would achieve emission reductions equivalent to command and control approaches and as expeditiously as possible. Throughout the years, there have been a number of amendments to the RECLAIM rules, including BARCT reassessments for NOx in 2005 and SOx in 2010. As a result of the January 2005 amendment, NOx RTCs were reduced by 7.7 tpd, approximately 22.5%, applied all 281 RECLAIM facilities. This reduction was imple mented in phases: 4 tpd by 2007 and an additional 0.925 tpd in each of the following 4 years. Figures 1.1 - 1.3 show the historical trend of NOx emissions, RTC allocations, and RTC price for compliance years 1994 - 2013 reflecting the fact that the NOx reductions specif ied by the January 2005 amendment did not upset the market or cause RTC prices to rise above the $15,000 per ton, which is the level specified in Rule 2015 that would require a program review.

Allocations Emissions

45000

40000

35000

30000

25000

20000

15000

10000

5000

0 Compliance Year Figure 1. 2 – Audited Emissions and RTC HoldingsNOx (tons)

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

### 15NOx Price ($ per ton) 60,000

50,000

40,000

30,000

20,000

10,000

0 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

2005-2012 Range: $1,162 - $5,491 per ton Percent of cost threshold: 8 – 37%

Avg. Discrete RTC Price $15K per ton Threshold

2002 2004 2006 2008 2010 2012 2014 Calendar Year 1994 1996 1998 2000 Figure 1.3 – NOx Discrete RT C Price versus Threshold

700,000

600,000NOx Price ($ per ton) 500,000

400,000

300,000

200,000

100,000

0 Avg. IYB RTC Price $609,187 per ton Threshold 2005 – 2012 Range: $48,146 - $202,402 per ton Percent of cost threshold: 8 -34%

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 Calendar Year

Note: IYB cost threshold is adjusted annually by CPI Figure 1.4 – NOx Infinite Year Block (IYB) RTC Price versus Threshold
According to the RECLAIM Annual Audit Reports, the vast majority of the RECLAIM facilities complied with their NOx RTC allocations and th eir aggregate RECLAIM NOx emissions remained below their NOx allocations for each compliance y ear since 2005. RECLAIM facilities had a high rate of compliance for covering emissions with RTCs. Th e same was true for all other years of the program except for 2000 and 2001 when there was a Cali fornia power crisis. Th e audited annual NOx emissions, NOx RTCs allocated for the universe, and unused RTCs are summarized in Table 1.1. Data show that approximately 21–30% RTCs in each of th e past 5 years were not used, approximately 5.45 tpd – 8.41 tpd.

### 16 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table 1. 1 – Audited Emissions, RTC Ho ldings and Unused RTCs from 2009-2013
Compliance Audited emissions RTC Holdings Unused RTCs Unused RTCs Year (tons) (tons) (tons) (%) 2009 7,306 10,377 3,071 30% 2010 7,121 10,053 2,932 29% 2011 7,302 9,690 2,388 25% 2012 7,691 9,689 1,988 21% 2013 7,326 9,699 2,373 24% Reference: Table 3-2, page 3-4, Annual RECLAIM Audit Report for 2013 Compliance Year 

## NOx RECLAIM Facilities

There were 281 276 facilities in RECLAIM as of June 2011 and 275 by the end of compliance year 2013. These facilities either elected to ente r the program or had NOx emissions greater than or equal to four tons per year in 1990 or any subsequent year. The distribution of the 20 tpd audited 2011 emissions and the 26.5 tpd RTC allocations for 2020 are shown in Figures 1.5 and 1.6. The top 37 facilities emitted 17.10 tpd NOx in 2011, more than 85% of emissions. The NOx emissions from RECLAIM facilities are generated from a wide range of equipment, and the top NOx emitting sources at the 37 facilities are refinery coke calciners, refinery fluidized catalytic cracking units, refinery and non-refinery gas turbines, refinery boilers and heaters, glass melting furnaces, sodium silicate furnaces, metal heat tr eating furnaces, internal combustion engines, and refinery sulfur recovery and tail gas incinerators. Cement kilns were the highest emitting stationary NOx source in 2008. The 2011 inventory did not incl ude the cement kilns in the inventory since they were non-operational and subs equently shut down in 2012. However staff did identify a new BARCT level for this operation and removed the equivalent amount of emissions from the remaining emissions in 2023 from the cement kiln. Figure 1.6 shows the amount of RTC holdings by sector for Compliance Year 2020 without considering 2015 BARCT levels and the proposed am endments. Refineries hold over half of the RTCs with the second most predominant RTC hol ding industry being electrical electricity generating facilities.

### 17 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Figure 1. 5 – Distribution of 20 tpd NOx Emissions (End of Compliance Year 2011)

Refineries 51%

Power Plants 21%

Cement 1% Glass 1% Investors 4% Others 23%

Figure 1. 6 – Distribution of 26.5 tpd RTC Holdings (End of Compliance Year 2020)

### 18 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Chapter 2 – Facility Emissions and RTC Holdings Projected Emissions and Emission Reductions
As stated in the 2012 AQMP and summarized in Table 2.1 below, NOx emissions from the RECLAIM facilities were projected to be about 27 tpd by 2023 (26.51 tpd total allocation rounded up to 27 tpd in the 2012 AQMP), representing 37% of the NOx emissions from stationary sources. Collectively, RECLAIM is the fourth largest source of NOx emissions in the Basin in 2023 as shown in Table 2.2. The 3-5 tpd of reductions for CMB-01 were es timated during the devel opment of the 2012 AQMP, however staff’s analysis of BARCT shows that additional reductions from RECLAIM NOx sources are possible. Staff is proposing thatthe RECLAIM program can contribute 14 tpd additional NOx emissions reductions by 2023. Table 2. 1 - Annual Average Emissions (tpd) by Major Source Category (2023 Base Year)
Source Category NOx Stationary Sources Fuel Combustion (non-RECLAIM) 27 Waste Disposal 2 Cleaning and Surface Coatings 0 Petroleum Production and Marketing 0 Industrial Processes 0 Solvent Evaporation Consumer Products 0 Architectural Coatings 0 Others 0 Misc. Processes 17 RECLAIM Sources 27 Total Stationary Sources 73 Total Mobile Sources 255
TOTAL 328 Reference: Table 3-6A, 2012 South Coast AQMP

### 19 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table 2. 2 - Top Ten Ranking of NOx Emission s from Highest to Lowest (2023 Base Year)

Rank Sources 1 Heavy-Duty Diesel Trucks 2 Off-Road Equipment 3 Ships & Commercial Boats 4 NOx RECLAIM 5 Locomotives 6 Aircraft 7 Residential Fuel Combustion 8 Heavy-Duty Gasoline Trucks 9 Passenger Cars 10 Light-Duty Trucks Reference: Table 3-10 of the 2012 South Coast AQMP


## Audited Facility Emissions and RTC Allocations

The 281 276 RECLAIM facilities, as of June 2011, e mitted 20.0 tpd NOx in 2011 adjusted to 20.7 tpd NOx using the electrical electricity generating facilities’ emissions in 2012 instead of 2011 emissions. Table 2.3 below lists the top 37 emitting facilities that contributed 17.10 tpd NOx emissions in 2011, more than 85% of the emissi ons from the entire NOx RECLAIM universe. The cement facility, the highest emitting NOx facilit y from 2008 to 2010, was not in operation in 2011. At the beginning of the RECLAIM program, the NOx RECLAIM universe was granted 40,534 tons per year (111 tpd) RTCs. This original amount of RTCs gradually dropped to a level of 12,486 tons per year (34.2 tpd) in 2005. In 2005, the RECLAIM rules were amended to implement a BARCT assessment that resulted in a cumulative RTC reduction of 7.7 tpd that was fully implemented in 2011. For compliance year 2011 and beyond, the RTC holdings for the NOx universe remain at a constant leve l of 9,677 tons per year (26.5 tpd).

### 20 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table 2. 3 - NOx Audited Emissions (2011 Compliance Year)

2011 Emissions (lbs) 2011 Emissions (tpd) 1 800089 EXXONMOBIL OIL CORPORATION 1,602,233 2.19 2 800030 CHEVRON PRODUCTS CO. 1,425,393 1.95 3 131003 BP WEST COAST PROD.LLC BP CARSON REF. 1,231,852 1.69 4 800436 TESORO REFINING AND MARKETING CO, LLC 1,171,965 1.61 5 171107 PHILLIPS 66 CO/LA REFINERY WILMINGTON PL 1,143,902 1.57 6 171109 PHILLIPS 66 COMPANY/LOS ANGELES REFINERY 673,652 0.92 7 800026 ULTRAMAR INC (NSR USE ONLY) 534,363 0.73 8 131249 BP WEST COAST PRODUCTS LLC,BP WILMINGTON 407,394 0.56 9 800183 PARAMOUNT PETR CORP (EIS USE) 104,249 0.14 10 151798 TESORO REFINING AND MARKETING CO, LLC 93,488 0.13 Total Refineries 11.49 1 46268 CALIFORNIA STEEL INDUSTRIES INC 464,990 0.64 2 800128 SO CAL GAS CO (EIS USE) 461,243 0.63 3 166073 BETA OFFSHORE 391,977 0.54 4 171960 TIN, INC. DBA INTERNATIONAL PAPER 327,637 0.45 5 18931 TAMCO 226,012 0.31 6 800074 LA CITY, DWP HAYNES GENERATING STATION 205,022 0.28 7 160437 SOUTHERN CALIFORNIA EDISON 204,132 0.28 8 800193 LA CITY, DWP VALLEY GENERATING STATION 166,413 0.23 9 4242 SAN DIEGO GAS & ELECTRIC 142,751 0.20 10 4477 SO CAL EDISON CO 137,290 0.19 11 7427 OWENS-BROCKWAY GLASS CONTAINER INC 135,486 0.19 12 119907 BERRY PETROLEUM COMPANY 131,857 0.18 13 129816 INLAND EMPIRE ENERGY CENTER, LLC 105,857 0.15 14 800075 LA CITY, DWP SCATTERGOOD GENERATING STN 103,988 0.14 15 115389 AES HUNTINGTON BEACH, LLC 98,993 0.14 16 51620 WHEELABRATOR NORWALK ENERGY CO INC 89,025 0.12 17 5973 SO CAL GAS CO 88,258 0.12 18 11435 PQ CORPORATION 81,270 0.11 19 115394 AES ALAMITOS, LLC 80,929 0.11 20 800335 LA CITY, DEPT OF AIRPORTS 73,245 0.10 21 129497 THUMS LONG BEACH CO 66,364 0.09 22 124838 EXIDE TECHNOLOGIES 62,824 0.09 23 15504 SCHLOSSER FORGE COMPANY 52,331 0.07 24 128243 BURBANK CITY,BURBANK WATER & POWER,SCPPA 49,983 0.07 25 800330 THUMS LONG BEACH 49,657 0.07 26 114801 RHODIA INC. 48,878 0.07 27 22911 CARLTON FORGE WORKS 48,839 0.07 Total non-refineries 5.61 Total for top 37 emitting facilities 17.10

### 21 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Major NOx Sources at Top Emitting Facilities
RECLAIM Rule 2012 establishes the requirements for monitoring, reporting and recordkeeping of NOx emissions under the RECLAIM program and classifies the NOx emitting equipment at the RECLAIM facilities into three categories: major NOx sources, large NOx sources, and NOx process units. RECLAIM facilities are required to monitor the emissions for each major NOx source with a Continuous Emissions Monitori ng System (CEMS) and report the emissions electronically on a daily basis via a remote terminal unit to the SCAQMD Central Station. The emissions for each large source are calculated base d on fuel usage or exhaust gaseous flow rates and reported electronically on a monthly basis to the SCAQMD Central Station. The emissions from all process units are reported on a quarterly basis. Table 2.4 shows that major NOx sources contri buted 88% of the NOx emissions from the NOx RECLAIM universe; large NOx sources and process units generated only 12% of the NOx RECLAIM emissions. Thus, staff focused on the major NOx sources at the top 37 emitting facilities to evaluate potential BARCT and emission reductions. The major NOx sources at the top 37 emitting RECLAIM facilities subject to new 2015 BARCT analysis are refinery fluid catalytic cracking units, refinery boilers and heaters >40 mmbtu/hr, refinery and non-refinery gas turbines, cement kilns, glass melting furnaces, sodium silicate furnaces, metal heat treating furnaces >150 mmbtu/hr, refinery sulfur recovery and tail gas incinerators, and internal combustion engines.
Table 2. 4 - NOx Emissions per Source Classification
Source Categories NOx Number of Percentage of (tons per day) Equipment Emissions Major NOx Sources 17.5 415 88% Large sources and Process Units 2.6 >1000 12% Total 20.0 100%

### 22 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Chapter 3 – 2015 Proposed BARCT and Emission Reductions
Previous BARCT Determinations
At the inception of the RECLAIM program, NOx starting allocations for 1994 and ending allocations for 2000 were based on the starting and ending emissions factors listed in Table 1 of Rule 2002 – Allocations for Oxides of Nitrogen (NOx) and Oxides of Sulfur (SOx) . For the 2003 ending allocations, 2000 ending a llocations were adjusted to be equal to the 1991 AQMP projected inventory for RECLAIM sources in 2003. The 2005 fu ture year allocations were set equal to the 2003 allocations. In 2005, the SCAQMD staff c onducted a BARCT assessm ent, and the rules were amended to reduce the RTCs by 7.7 tpd implemented by 2011. Table 3 of Rule 2002 was added to record the 2005 BARCT levels. The BARCT levels were kept at the 2000 ending emission factors as shown in Table 2 of Rule2002 for individual equipment categories where improved control technologies we re not yet deemed applicable or cost-effective in the 2005 BARCT assessment. 

## Proposed 2015 BARCT

Staff is proposing the BARCT levels tabulated in Table 3.1 and estimating that these 2015 BARCT levels will provide about 8.8 tpd in NOx emission reductions (6.00 tpd for refinery sector and 2.77 tpd for non-refinery sector) beyond what could be achieved by the 2005 BARCT levels for each category of major emitting sources at the top emitting facilities. Further discussions of NOx control technologies, proposed BARCT levels, estimated emission reduc tions, costs and cost effectiveness values are discussed in Part I of this staff report for the refinery sector and Part II for the non-refinery sector. The RTC reductions to implement BARCT are 14 tpd. See Chapter 5 and Part III of this staff report. Part I – BARCT Analyses for Refinery Sector: Appendix A Fluid Catalytic Cracking Units Appendix B Boilers and Heaters, >40-100 mmbtu/hr Appendix C Refinery Gas Turbines Appendix D Coke Calciner Appendix E Sulfur Recovery Units Tail Gas Incinerators Part II – BARCT Analyses for Non-Refinery Sector: Appendix M Cement Kilns Appendix N Container Glass Melting Furnaces Appendix O Sodium Silicate Furnace

### 23 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Appendix P Metal Melting Furnaces > 150 mmbtu/hr Appendix Q Non-Refinery Gas Turbines Appendix R Non-Refinery, Non-Electrical Electricity Generating Facility Internal Combustion Engines Appendix S Non-Refinery Boilers > 40 mmbtu/hr

Table 3. 1 - 2015 Proposed BARCT Le vels and Emission Reductions

Incremental Emission Refinery Sector 2015 BARCT Level Reductions Beyond 2000/2005 BARCT (tpd) Fluid Catalytic Cracking Units 2 ppmv at 3% O2 0.43 Boilers and Heaters >40 mmbtu/hr 2 ppmv or 0.002 lb/mmbtu 0.94 Gas Turbines 2 ppm at 15% O2 4.14 Coke Calciner 10 ppmv at 3% O2 0.17 Sulfur Recovery Units Tail Gas Incinerators 2 ppmv at 3% O2 or 95% reduction 0.32 Total 6.00

Incremental Emission Non-refinery Sector 2015 BARCT Level Reductions Beyond 2000/2005 BARCT (tpd) Cement Kilns 0.5 lb/ton clinker 1.29 (note) Container Glass Melting Furnaces 80% reduction 0.24 Sodium Silicate Furnace 80% reduction 0.09 Heat Treating Furnaces >150 mmbtu/hr 9 ppmv at 3% O2 0.56 Gas Turbines (non-OCS) 2 ppmv at 15% O2 1.04 ICEs (non-OCS) 11 ppmv at 15% O2 0.84 Total 2.77 Note: The 1.29 tpd emission reductions from cement kilns were not included in the 2.77 tpd emission reductions because the cement facility was not in operation in 2011. Cement kilns were the highest source of NOx emissions in 2008, thus staff conducted a B ARCT analysis for cement kilns and reduced the remaining emissions pr ojected to the 2023 level for the cement facility to the BARCT level.

### 24 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Co-Benefits of Energy Efficiency Projects
For the refinery sector, in addition to the 6.00 tpd emission reductions shown in Table 3.1, there are about 0.6 to 0.7 tpd NOx emission reductions thatare expected to have occurred concurrently with the energy efficiency projects to reduc e greenhouse gases as shown in Table 3.2. According to CARB staff, these co-benefits reductions were not yet included in the baseline and SCAQMD staff did not include the co-benefits in this proposal. See Appendix K for further details.

Table 3. 2 - Co-Benefits of Emission Re ductions for Energy Efficiency Projects
Projects Completed and ongoing (2007-2011) Emission Reductions (tpd) 0.6 Scheduled 0.05 Under investigation 0.07 - 0.08 Total 0.7

### 25 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Chapter 4 – Costs and Cost Effectiveness
This chapter discusses both the preliminary anal ysis in December 2014 and the revised analysis in 2015. 

## Staff’s Preliminary Estimates
Staff preliminary analyses as of December 2014 for costs and cost effectiveness are discussed in Part I, Appendices A – E, for the refinery sector and Part II, Appendices M – S, for the non-refinery sector, respectively. A summary of the methods us ed for costs and cost ef fectiveness analyses and the results of these detailed analyses are provided in this Chapter. The Present Worth Values (PWV) of a control device are the total costs to install and operate the control device estimated at the present currency value. The PWV consists of the Total Installed Costs (TIC) and Annual Operating Costs (AC) during the entire economic life of the control equipment using the Discounted Cash Flow (DCF) Method as follows:
PWV = TIC + (15.62 x AC) Where: PWV = Present Worth Value, $ TIC = Total Installed Costs, $ AC = Annual Operating Costs, $ 15.62 = a factor to estimate the cumulative annual operating costs during a 25-year life of a control device

The incremental cost effectiveness value of a control device is estimated as follows:

CE incremental = (PWV 2015 BARCT – PWV 2000/05 BARCT ) /(ER 2015 BARCT – ER 2000/05 BARCT )/25/365

Where:

CE incremental = Incremental Cost Effectiveness, $/ton PWV 2015 BARCT - PWV 2000/05 BARCT = Incremental costs to achieve additional control to meet the 2015 BARCT level from the 2000/2005 BARCT level ER 2015 BARCT - ER 2000/05 BARCT = Incremental emission reductions to achieve the 2015 BARCT level from the 2000/2005 BARCT level

The incremental costs and cost effectiveness were calculated based on the 2011-2012 baseline emissions and the DCF method. St aff also presented the cost ef fectiveness estimated with the

### 26 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Levelized Cash Flow (LCF) method. In the cost effectiveness analysis using the DCF method, staff used a cutoff level of $50,000 per ton. The $50,000 per ton cutoff is based on the policy developed during the 2008 – 2010 SOx RECLAIM ru le amendment that was adopted by the District Governing Board. The results of sta ff’s preliminary estimates in 2014 for PWVs and cost effectiveness values are summarized in Tables 4.1 and 4.2; and the revised estimates are summarized in Tables 4.3 and 4.4.


## Consultants’ Estimates
In the Fall of 2014, the SCAQMD staff contracted with two consultants, NEC and ETS, to conduct independent studies on costs and co st effectiveness. The consul tants’ reports are included as separate documents (Addenda 1 and 2). Table 4.1 below shows a comparison between staff’s and NEC’s estimates for the refinery sector, and Ta ble 4.2 shows a comparison between staff’s and ETS’s estimates for the non-refinery sector.
Refinery Sector For the refinery sector, as shown in Table 4.1, NEC and staff recommended BARCT levels of 2 ppmv for gas turbines, FCCUs, boilers/heaters, and SRU/TG incinerators. For the refinery coke calciner, NEC recommended a BA RCT level of 5 - 10 ppmv instead of 2 ppmv previously recommended by staff. Staff agreed wi th NEC’s recommendation and changed the recommendation to 10 ppmv BARCT for the coke calc iner. Different approaches were used to estimate the SCR costs for FCCUs, boilers/heaters and SRU/TG incinerators, an adjustment was made to the proposed shave amount to account for the different engineering and cost assumptions. Please refer to Part I, Appendix F - J, for furthe r discussion. Table 4.3 shows the ranges of PWVs and cost effectiveness values for the refi nery sector based on the revised proposal.

### 27 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table 4. 1 – Initial Proposal - BARCT Levels, Costs and Cost Effectiveness - Refinery Sector (December 2014)

Equipment Proposed Staff’s Estimates Estimates Using Incremental Category 2014 NEC’s Information DCF CostBARCT Effectiveness Incremental PWVs Incremental PWVs $/ton NOx Reductions ($M) Reductions ($M) Reduced (tpd) (tpd) Gas Turbines 2 ppmv 4.14 97.7 4.14 52.7 1K - 3K FCCUs 2 ppmv 0.43 152 0.43 211 3K - 18K Coke Calciner 5 ppmv 0.21 (1) 22 - 61 0.17 (2) 39.5 11K - 25K Boilers/Heaters 2 ppmv 1.05 254.5 0.61 162 27K - 29K >40 mmbtu/hr SRU/TG 2 ppmv 0.35 49 - 68 0.32 120 15K - 48K Incinerators Total 6.18 575 - 633 5.67 585 7K - 12K (3) Note: 1) Based on 5 ppmv BARCT, 2) Based on 10 ppmv BARCT, 3) Weighted average by NOx reductions Non-Refinery Sector For the non-refinery sector, ETS agreed with the proposed BARCT levels recommended for all categories. ETS’s estimated costs and incremental costs were slightly higher than staff’s estimates as shown in Table 4.2. Table 4.4 shows the revised ranges of PWVs and cost effectiveness values for the non-refinery sector.

### 28 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table 4. 2 – Initial Proposal - BARCT Levels, Costs and Cost Effectiveness - Non-Refinery Sector (December 2014)

Proposed 2014 Incremental St aff’s ETS’s Incremental BARCT Reductions PWVs PWVs DCF CE (tpd) ($M) ($M) $/ton NOx Reduced Cement Kilns 0.5 lb/ton clinker 1.32 34 - 107 36 - 112 3 - 10K Container Glass 0.24 lb/ton pulled 0.24 4 - 14 6 - 15 3 - 7K Sodium Silicate Furnace 1.28 lb/ton pulled 0.09 2.8 - 4.6 3 - 4.6 4 - 6K Metal Heat Treating 9 ppmv @ 3% O2 0.56 8 - 10 8 - 10 3 - 3.8 K Furnaces >150 mmbtu/hr Gas Turbines 2 ppmv @15% O2 1.04 3 - 14 3 - 14 5 - 36K ICEs 11 ppmv @15% O2 0.84 0.9 - 4 0.9 - 4 5 - 8K Boilers >40 mmbtu/hr No new BARCT 0 0 0 Total 6.18 53 - 154 57 - 160 4 - 15 K (1, 2) Note: 1) LCF ranges from $5 K - $57 K per ton, 2) Weighted average by NOx reductions



## Staff Recommendations
After the facility visits and the consultants’ analyses were completed, staff revisited the cost estimations and made modifications to th e preliminary proposals. Staff’s revised recommendations are presented below.
Refinery Sector

Staff’s current recommendations for the refinery sector are tabulatedin Table 4.3. Please refer to Part I, Appendices A-J fo r additional information.

### 29 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table 4. 3 - Staff’s Revised Recommendation for Refinery Sector (May 2015)

2015 BARCT Incremental Reductions (tpd) PWVs ($M) Incremental Cost Effectiveness ($K/ton DCF) Note

FCCUs 2 ppmv 0.43 152 – 391 3 – 13 1 Gas Turbines 2 ppmv 4.14 53 – 98 1 – 3 2 Boilers/Heaters >40 mmbtu/hr 2 ppmv 0.94 237 28 3 Coke Calciner 10 ppmv 0.17 40 - 91 19 – 25 4 SRU/TG Incinerators 2 ppmv 0.32 83 - 106 28 – 40 5
Total 6.00 565 – 923 10 – 17 6
Notes:

1) See Appendix A. The PWV of $152M are for the case where all 5 refineries would install SCRs. The PWV of $391 M are for the case where SCRs would be installed at Ref 5 and 6 and LoTOx and scrubbers at Ref 4, 7 and 9 to reduce both NOx and SOx. 2) See Appendix C. The PWV of $53 M was estimated by NEC for adding catalysts to all SCRs. The PWV of $98 M was derived by SCAQMD staff for adding catalysts to Ref 1’s SCRs and new SCRs to Ref 4 - 7. 3) See Appendix B. 4) See Appendix D. The PWV of $40M was estimated by NEC for LoTOx technology and $91 M was staff’s estimates for Tri-Mer technology 5) See Appendix E. The PWV of $83 M was for SCRs and $106 M for LoTOx applications 6) Incremental cost effectiveness is the weighted aver age by NOx reductions. Low end of incremental cost effectiveness = $565 M/ (6*25*365) = $10,320 per ton NOx reduced. High end of incremental cost effectiveness = $923 M/ (6*25*365) = $16,858 per ton NOx reduced.

### 30 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Non-Refinery Sector

Table 4.4 tabulates staff’s current recommendations for the non-refinery sector. Please refer to Part II, Appendices M-R for further information.

Table 4. 4 - Staff’s Recommendation fo r Non-Refinery Sector (May 2015)

2015 BARCT Incremental Reductions (tpd) PWVs ($M) Incremental Cost Effectiveness ($K/ton

DCF) Note

Cement Kilns 0.5 lb/ton clinker 1.29 61 - 152 5 - 11 1 Container Glass Melting Furnaces 0.24 lb/ton glass pulled 0.24 6 - 15 3 - 7 2
Sodium Silicate Furnace 1.28 lb/ton glass pulled 0.09 3.0 - 4.6 4 - 8 3 Metal Heat Treating Furnace > 150 mmbtu/hr 9 ppmv at 3% O2 0.56 8 - 10 3 - 3.8 4
Gas Turbines 2 ppmv at 3% O2 1.04 ~109 5 - 36 5 ICEs 11 ppmv at 15% O2 0.84 ~37 5 - 8 6 Total 4.06 224 - 328 6 - 9 7, 8, 9, 10
Note: 1) Refer to Appendix M 2) Refer to Appendix N 3) Refer to Appendix O 4) Refer to Appendix P 5) Refer to Appendix Q 6) Refer to Appendix R 7) Incremental costs effectiveness is the weighted averag e by NOx reductions. With cement kilns: low end of incremental cost effectiveness = $224 M/ (4.06*25*365) = $6 K per ton NOx reduced, and high end of incremental cost effectiveness = $328 M/ (4.06*25*365) = $9 K per ton NOx reduced. 8) The incremental emission reductions would be 4.06 tpd including the incremental reductions for the cement kilns. Without the cement kilns, the incremental emission reductions would be 2.77 tpd. 9) The range for PWVs would be $224 M – $328 M including the PWVs for the NOx control device for cement kilns. The range of PWVs would be $163 M - $176 M without the control devices for cement kilns. 10) Incremental costs effectiveness is the weighted average by NOx reductions. Without cement kilns: low end of incremental cost effectiveness = $163 M/ (2.77*25*365) = $6 K per ton NOx reduced, and high end of incremental cost effectiveness = $176 M/ (2.77*25*365) = $7 K per ton NOx reduced.

### 31 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Chapter 5 - RTC Reductions
Remaining Emissions

As discussed in the Public Pro cess section, staff started the disc ussion with stakeholders on the calculation method that would be used to estimate the RTC reductions in 2013. One of the parameters used in the calculation for the RTC reductions is the remaining emissions projected to 2023. The 2023 remaining emissions estimates by staff we re first presented to the stakeholders at the January 22, 2014 Working Group Meeting. Staff later refined the numbers and presented them to the stakeholders in the July 31, 2014 and April 29, 2015 Working Group Meetings. The changes made are summarized below.
Refinery Sector Table 5.1 tabulates the estimated 2023 remaining e missions for each NOx source category in the refinery sector. In 2014, staff estimated the to tal 2023 remaining emissions to be 2.56 tpd. In 2015, staff revised the number to 2.76 tpd as a result of the following changes:

x The BARCT level for coke calciner was chan ged from 2 ppmv to 10 ppmv. As a result, the remaining emissions for coke calciner increased to 0.08 tpd.

x The costs of control for boilers/heaters and SRU/TG incinerators were revised to be higher. As a result, the cost effectiveness for several boilers/heaters and one incinerator became higher than the policy threshold of $50,000 per ton, and these units were excluded from the equipment that contributed to the emission reductions. The remaining emissions for the boilers/heaters >40 mmbtu/hr increased to 0.85 tpd, and the remain ing emissions for the SRU/TG incinerators increased to 0.11 tpd.32Draft Final Staff Report – NOx RECLAIMOctober 6November December 4, 2015Table 5. 1 - Remaining Emissions for Refinery SectorTotal Noof Units2011Emissions(tpd)2000/2005BARCT2011 Emissionsat 2000/2005BARCT(tpd)2015 BARCT2011Emissions at2015 BARCT(tpd)2023 EmissionReductionsBeyond2000/2005BARCT(tpd)2023 Emissionat 2015 BARCTwith GF = 1(tpd)FCCUs/CO Boilers 8 1.08 85% control 0.60 2 ppmv 0.17 0.43 0.17Turbines/Duct Burners 21 1.33 62.27 lbs/mmcft 4.86 2 ppmv 0.72 4.14 0.72Coke Calciner 2 0.55 30 ppmv 0.25 10 ppmv 0.08 0.17 0.08SRU/TG Incinerators 17 0.43 RV 0.432 ppmv (or95% control)0.11 0.32 0.11Boilers/Heaters > 110 mmbtu/hr 73 4.88 5 ppmv 0.82 2 ppmv 0.38 0.44 0.38Boilers/Heaters >40-110 mmbtu/hr 69 2.00 25 ppmv 0.97 2 ppmv 0.47 0.50 0.47Boliers/Heaters 20-40 mmbtu/hr 52 0.45 9 ppmv 0.10 n/a 0.10 0.00 0.10Boilers/Heaters <20 mmbtu/hr 18 0.06 12 ppmv 0.02 n/a 0.02 0.00 0.02Other Major/Large Sources 5 0.11 n/a 0.10 n/a 0.10 0.00 0.10Other Process Units n/a 0.60 n/a 0.60 n/a 0.60 0.00 0.60Total 265 11.50 8.76 2.76 6.00 2.76

### 33 Draft Final Staff Report – NOx RECLAIM October 6NovemberDecember 4, 2015
Non-Refinery Sector

Table 5.2 tabulates the estimated 2023 remaining emissions for each NOx source category in the non-refinery sector. In 2014, staff estimated th e 2023 remaining emissions for the non-refinery sector to be 8.77 tpd. In 2015, staff revised th e number to 7.47 tpd as a result of the following changes:

x The baseline for electrical el ectricity generating facilities was changed from 2011 to 2012. The 2011 and 2012 baseline emissions we re 1.45 tpd and 2.50 tpd, respectively. Staff also used either the BACT level or the le vel stated in the permit conditions to esti mate the emission reductions beyond the levels that could be achieved by the 2005 BARCT. In addition, staff used the most recent growth factor of 0.868 to estimate the remain ing emissions for the electrical electri city generating facilities. As a result of these changes, the 2023 remaining emissions for electrical el ectricity generating facilities were changed to 2.04 tpd.

x The remaining emissions from non-electrical elec tricity generating facilities were changed to 1.37 tpd; and

x The remaining emissions from other sources were changed to 4.06 tpd.34Draft Final Staff Report – NOx RECLAIMOctober 6November December 4, 2015Table 5. 2 - Remaining Emissions for Non Refinery Sector (May 2015)

### 35 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015



## Calculation Method for RTC Reductions

The RTC reductions are calculated as follows: RTC Reductions = RTC Holdings – (Remaining Emissions x Compliance Margin)

Where RTC Holdings = 26.5 tpd Remaining Emissions = (R Refinery + R Non-Refinery + R Adjustment ) R Refinery = Remaining emissions for refine ry sector x Growth Factor R Non Refinery = Remaining emissions for non-refinery sector x Growth Factors R Adjustment = Potential adjustments set aside for new electrical electricity generating facilities Compliance margin = 10% as provided in the previous RECLAIM amendments An example shown below was presented atthe April 29, 2015 Working Group Meeting:

R Refinery = 2.76 tpd including growth factor of 1 as shown in Table 5-1 R Non Refinery = 7.47 tpd including growth factor of 1.1 as shown in Table 5-2 R Adjustment = 0.07 tpd potential adjustments for new electrical electricity generating facilities due to SONGS shutdown and 0.29 and 0.10 for CPCC and other shutdown facilities RTC Reductions = 26.5 – ([(2.76 + 7.47 + 0.07) x 1.1] + (0.29 + 0.10)) = 26.5 – 11.7 = 14.8 tpd 

## Regional NSR Holding Account for Electric ity al Generating Facilities
Staff has received input from several electric ityal generating facility operators that have concerns with concurrent compliance with the RTC allo cation shave and the new source review (NSR) holding requirements per Rule 2005. New facilities that entered in to RECLAIM after October 15, 1993 must hold RTCs for all of their equipment at the permitted potential to emit (PTE) level at the beginning of every compliance year. Pre-RE CLAIM power producing facilities only need to hold RTCs for one year if their PTEs increase, unless their new PTEs exceed their initial 1993 allocation. Electric ity al producing generating fac ilities often operate at a capacity factor well below the PTE level during any given complianc e year. The combustion equipment for these

### 36 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 facilities is also already at the BARCT or BACT emission level. These facilities would be shaved and be subject to complying with the NSR holding requirements as well as their annual emission reconciliation requirements. Staff has proposed the creation of a Regional NSR Holding Account to help address the NSR holding requirements programmati cally for all post-1993 electric ity al producing generating facilities. This account would reduce the indivi dual facility NSR hold requirements by the amount that they were shaved and would be comprised of the shaved RTCs from these facilities as discrete credits. All electric ity al generating facilities woul d be allowed to access this account to offset emissions (rather than just satisfy NSR holding requirements) if the G overnor of California declares a state of emergency regarding reliable energy supply or grid stability in the Basin. The size of the Regional NSR Holding Account would be equivalent to the RTCs shaved from the affected post-1993 electrical electri city generating facilities. This approach serves two purposes. First, it provides relief from the different and burdensome NSR holding requirements for these newer facilities relative to older electric ity al generation generating facilitie s. Second, it provides an emergency source of RTCs to be accessed in the case of a power crisis. Any new electric ity al generating facility that enters RECLAIM after the proposed amendment would still be subject to the full multi-year NSR holding requirements. 

## Staff Proposal and CEQA Alternatives
Table 5.3 summarizes the staff proposal which incl udes a NOx RTC shave of 14 tpd rather than the 14.8 tpd calculated above. The 0.8 tpd differen ce is to account for comments received from stakeholders regarding uncertainties in the BARCT analysis, and to provide some additional compliance margin. Staff is currently proposing that the 14 tpd RTC reductions be distributed to 56 facilities and investors that co llectively hold about 90% of the 26.5 tpd RTCs. The 56 affected facilities include 9 major refineries, 21 electrical electricity generating facilities, and 26 other top emitting facilities as shown in Ta ble 5.5. Staff is proposing not to shave the remaining 219 facilities that hold only 10% of the 26.5 tpd RT Cs because there was limited or no new BARCT identified for other types of equi pment and operations there. Other approaches to determine the RTC reductions as shown in Table 5.4 were analyzedas project alternatives in the CEQA analysis. For further information, please refer to PartIII, Appendix U of this staff report. Staff is proposing the followi ng implementation schedule: 2016: 4 tons per day 2018: 2 tons per day 2019: 2 tons per day 2020: 2 tons per day 2021: 2 tons per day 2022: 2 tons per day

### 37 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

As shown in Table 1-1 of Chapter 1, in the pa st five years from 2009-2013, the unused RTCs in the NOx RECLAIM program ranged from 5.5 to 8 tpd, and thus staff is proposing a reasonable initial 4 tpd RTC reduction in 2016. Additional BARCT implement ation will take about 2 – 4 years for planning, permitting, and construction, a nd staff is proposing that the remaining shave of 10 tpd take place between 2018 and 2022.

Table 5. 3 - Staff Proposal - Affected Facilities and Percent Shave Major Refineries and Investors Non-Electrical Electricity generating

facilities Electrical Electricity generating

facilities Bottom 10% of RTC Holders Total

No of facilities Current RTCs RTC Reductions Remaining RTCs

Percent Shave 9 14.6 9.6

5 9.6/14.6 = 66% 26 21 9.1 4.4 4.7 4.4/9.1 = 49% 219 2.8

0 2.8 0% 275 26.5 14.0 12.5

Note that investors are counted as one facility and grouped with the refineries.

Table 5. 4 - Alternatives for CEQA Analysis
Major Non-Major Electrical Bottom Alternative Refineries + Re fineries/ Elect ricity 10% of Investors Facilities Generating RTC Facilities Holders 1 Shave 14 tpd uniformly across all 275 facilities 53% 53% 53% 53%

2 Shave 15.87 tpd (w/o 10% compliance 60% 60% 60% 60% margin) uniformly across all 275 facilities Shave 8.8 tpd (the difference in emission 33% 33% 33% 33% 3 reductions between previous BARCT and 2015 BARCT) uniformly across all 275 facilities 4 No project 0% 0% 0% 0% Shave 14 tpd weighted by BARCT reduction 66% 37% 37% 37% 5 contribution and distributed to all 275 facilities

### 38 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table 5. 5 - List of Facilities and Investors that would have RTCs Reduced

Facility ID Name

800030 CHEVRON PRODUCTS CO. 800089 EXXONMOBIL OIL CORPORATION 174655 TESORO REFINING & MARKETING CO, LLC 800436 TESORO REFINING AND MARKETING CO, LLC 171107 PHILLIPS 66 CO/LA REFINERY WILMINGTON PL 800026 ULTRAMAR INC 115394 AES ALAMITOS, LLC 115663 EL SEGUNDO POWER, LLC 800074 LA CITY, DWP HAYNES GENERATING STATION 800128 SO CAL GAS CO 800075 LA CITY, DWP SCATTERGOOD GENERATING STN 46268 CALIFORNIA STEEL INDUSTRIES INC 115536 AES REDONDO BEACH, LLC 160437 SOUTHERN CALIFORNIA EDISON 171109 PHILLIPS 66 COMPANY/LOS ANGELES REFINERY 174591 TESORO REF & MKTG CO LLC,CALCINER 115315 NRG CALIFORNIA SOUTH LP, ETIWANDA GEN ST 152707 CPV SENTINEL LLC 169754 OXY USA INC 115389 AES HUNTINGTON BEACH, LLC

7427 OWENS-BROCKWAY GLASS CONTAINER INC 18931 TAMCO 4477 SO CAL EDISON CO 800183 PARAMOUNT PETR CORP 43201 SNOW SUMMIT INC 172005 NEW- INDY ONTARIO, LLC 146536 WALNUT CREEK ENERGY, LLC 800189 DISNEYLAND RESORT 156741 HARBOR COGENERATION CO, LLC 151798 TESORO REFINING AND MARKETING CO, LLC 128243 BURBANK CITY,BURBANK WATER & POWER,SCPPA 11435 PQ CORPORATION 4242 SAN DIEGO GAS & ELECTRIC 115314 LONG BEACH GENERATION, LLC 17953 PACIFIC CLAY PRODUCTS INC 153992 CANYON POWER PLANT 800127 SO CAL GAS CO 800193 LA CITY, DWP VALLEY GENERATING STATION 119907 BERRY PETROLEUM COMPANY 25638 BURBANK CITY, BURBANK WATER & POWER 124838 EXIDE TECHNOLOGIES 51620 WHEELABRATOR NORWALK ENERGY CO INC 5973 SO CAL GAS CO 800168 PASADENA CITY, DWP

3968 TABC, INC 8582 SO CAL GAS CO/PLAYA DEL REY STORAGE FACI 155474 BICENT (CALIFORNIA) MALBURG LLC

### 39 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Facility ID Name

800181 CALIFORNIA PORTLAND CEMENT CO 166073 BETA OFFSHORE 114801 SOLVAY USA, INC. 800153 US GOVT, NAVY DEPT LB SHIPYARD

8547 QUEMETCO INC 1073 BORAL ROOFING LLC 700126 GENERAL ELECTRIC COMPANY 129816 INLAND EMPIRE ENERGY CENTER, LLC 127299 WILDFLOWER ENERGY LP/INDIGO GEN., LLC INVESTORS

### 40 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Chapter 6 – Summary of the Pr oposed Changes in Rule Language and Draft Program En vironmental Assessment
Appendix X contains more detailed information regarding the changes described below. 

## Rule 2001 (g)(1) to (4) and (i)(1)(K) and (i)(2)(O) – Electricity Generating Facilities Opt-out of NOx RECLAIM
Rule 2001 includes a provision that would allow th e owner or operator of an electricity generating facility (EGF) to opt out of the NOx RECLAIM program. An opt-out plan would need to demonstrate that at least 99 percent of the EGF’s NOx emissions for the most recent 3 compliance years are at current BARCT or BACT. The rule specifies how New Source Review requirements would be met, how RTCs will be handled, and that Facility Permit amendments would be required to ensure that BARCT or BACT levels would be maintained. The EGF operator would need to comply with any source specific rule limits as quickly as possible, but no later than 3 years after approval of their opt-out plan. The owner or operator at multiple EGFs under common control would have one opportunity to apportion th e NOx limits among its facilities. Monitoring, reporting, and recordkeeping requirements of Ru le 2012 and its associated protocols would continue to apply unless the Executive Office approves an alternative plan that is sufficient to determine compliance with all applicable rules. As mentioned above, an EGF may opt out of RECLAIM provided it meets certain criteria. Specifically, the facility will be subject to a c ondition limiting the facility’s NOx emissions, for a facility existing as of October 1993, to the amount of RTCs held by the facility as of September 22, 2015, and for a facility built after October 1993, to the amount of RTCs required to be held pursuant to Rule 2005. However, if the operator ha s more than one facility subject to RECLAIM upon removing all of the fac ilities from RECLAIM simultaneously , the operator has a single opportunity to re-distribute the RTCs holdings amon g the various facilities in such a way that the RTCs held for each facility will not exceed the maximum emissions that can be generated by the equipment permitted at th at facility based on the existing permit conditions. Once the facility is re-issued its permit without RECLAIM requirements, subsequent modifications to the facility will be subject to provisions of Regulation XIII – New Source Review for NOx, as well as other pollutants. There are f our possible scenarios that may trigger New Source Review (NSR) provisions for NOx. The table below shows the poten tial conditions that may be imposed for each scenario:

### 41 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Scenario Offset Exemption Emission Limiting Conditions Replacement of existing equipment with other equipment that is functionally equivalent and no increase in maximum emissions 1304 (a)(1) Facility annual emission limit remains; no need for additional individual equipment limit for the remaining existing equipment Replacement of an electric utility steam boiler with combined cycle gas turbine(s), intercoo led, chemicallyrecuperated gas turbines, other advanced gas turbine(s); solar, geothermal, or wind energy or other equipment, to the extent that such equipment will allow compliance with Rule 1135 or Regulation XX rules 1304 (a)(2) Facility annual emission limit remains; no need for individual equipment limit for the remaining existing equipment Concurrent modification or replacement of existing equipment or removal and addition of different equipment that result in a net decrease in emission potential 1304 (c)(2) Facility annual emission limit remains; no need for individual equipment limit for the remaining existing equipment

Modification or replacement of existing equipment that result in a net increase of emissions, or construction of new equipment None May apply for individual equipment limits prior to applying for modification or new construction; Facility annual emission limit will be updated to account for offset provided for new or modified source


## Rule 2002 (f)(1) – BARCT Proposed Levels and RTC Reductions
The staff proposal of the new BARCT levels fo r the refinery and non-refinery sectors are summarized in Table 6 of Rule 2002. The proposal would result in a programmatic re duction of 14 tons per day RTC holdings over 7 years. Four tons per day would be reduced in2016 and the remainder would be reduced in equal increments from 2018 to 2022. There would be no reductions proposed for the year 2017. These reductions are reflected in subparagraphs (f)(1)( B) and (f)(1)(C). Subparagraph (f)(1)(B) includes all of the Major Refineries and Investors. The Major Refineries are listed in Table 7 of Rule 2002. Subparagraph (f)(1)(C) includes all other facilities subject to the reduction in NOx RTCs. These facilities are listed in Table 8 of Rule 2002.

### 42 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The remaining NOx RTCs after a shave for any compliance year would be the Tradable/Usable NOx RTC Adjustment factor in (f)(1)(B) multip lied by the RTC holding s (as of September22, 2015) of all the Major Refineries listed in Table 7 plus the Trad able/Usable NOx RTC Adjustment factor in (f)(1)(C) multiplied by the RTC holding s (as of September 22, 2015) of all the facilities listed in Table 8. Please see Appendix U fo r further explanation on how the factors in subparagraphs (f)(1)(B) and (C) were derived. Appendix U also contains the list of facilities including NOx RTC holders not designated as Facility Permit Holders as of September 22, 2015, except any NOx RTC holders listed in Table 8. Since the RTC reductions specified in subparagraph (f)(1)(A) have been realized, the conversion of non-tradable/non-usable NOx RTCs to tradable/usable NOx RTCs is no longer applicable to the RTC reductions specified in this subparagrap h. The tradable/usable NOx RTCs specified in subparagraph (f)(1)(A) would remain intact and used for calculating RTC reductions for facilities entering the RECLAIM program. However the same approach in converting adjustment factors previously specified in subparagraph (f)(1)(A) would now be applied to the RTC reductions specified in subparagraphs (f)(1)(B) and (f)(1)(C). Subparagraphs (f)(1)(B) and (f)(1)(C) also include adjustment factors to obtain Non-tradable/Nonusable holdings. The quantity of Non-tradable/Non-usable NOx RTCs is equal to the incremental shave amount in the given compliance year. Subparagraph (f)(1)(G) and (f)(1)(H) specify that shaved RTCs from newer electrical electricity gen erating facilities listed in Table 9 will be used to fund a Regional NSR Holding Account that can be used, along with th eir Non-tradable/Nonusable holdings, by these facilities to help meet their ongoing NSR holding requirements. Subparagraph (f)(1)(E) updates the 12-month rollingaverage trigger to $22,500 per ton for discrete credits. A trigger level of $35,000 per ton has been added for a 3-month rolling average in subparagraph (f)(1)(I). If RTC prices exceed either of these levels, a report to the Board and a program review are required. Subparagraph (f )(1)(J) includes a 12-month rolling average for Infinite Year Block (IYB) RTCs of $200,000 per ton. If credit prices are lower than this amount beginning in 2019, then a report to the Board is also required. Subparagraph (f)(1)(I) describes provisions for conversion of Non-tradable/Non-usable holdings to Tradable/Usable NOx RTCs if the 12-month rolling average RTC price exceeds $22,500 per ton. This trigger corresponds to the adopted 2012 AQM P cost effectiveness threshold that triggers additional analysis of proposed rules. Similarly, (f)(1)(I) also requires that the Executive Officer’s report to the Board on the trigger price also in clude a commitment and sche dule to conduct a more rigorous cost-effectiveness, market analysis, and socioeconomic impact assessment of the RECLAIM program.

### 43 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Subparagraph (f)(1)(LM) clarifies the method for determining allocations for existing facilities that enter RECLAIM after the date of adoption of the proposed amendments. 

## Rule 2002 (f)(4) and (f)(5) – Regional NSR Holding Account and State of Emergency Related to Elect rical Electricity Generating Facilities
A new electricricityal generating facility (EGF), along with all new RECLAIM facilities, must hold sufficient RTCs to offset their entire potential to emit (PTE) for one year prior to commencement of operation and at the beginning of every compliance year thereafter. These requirements are triggered in cases where a facility incurs an emission increase as defined under Rule 2005(d) – Emission Increase. Electrical generating facilitiesEGFs oftenm have PTEs that far exceed their actual emissions, and cannot readily reduce their PTEs given that they must be available for grid support if called upon. Given this burdensome requirement, staff is proposing to create ana Regional NSR Holding Account, held by the SCAQMD, that would be used for the purpose of helping such facilities comply with the NSR requirements specified in Rule 2005. These proposed requirements are specified in Rule 2002 paragraph (f)(4). The RTCs in the Regional NSR Holding Account would not be available to offset ac tual emissions, except for the situation described below. Staff is proposing in paragraph (f)(5) that during a State of Emergency declared by the Governor related to electricity demand or power grid stability in the Basin, any electrical generating facilityEGF can use their Non-tradable/Non-usable NOx RTC holdings to offset their emissions after exhausting their Tradable/Usable holdings. Furthermore, if their Non-tradable/Non-usable NOx RTC holdings are exhausted, they may apply for the use of NOx RTCs in the Regional NSR Holding Account on a quarterly basis. Subparagraphs (f)(4)(i) – (iii) describe the criteria that the Executive Officer must consider in determining the amount and the distribution of these RTCs. If the total RTCs requested exceeds the supply in the Account, the RTCs will be distributed proportionately according to the verified offset needs of the requesting facilities The RTCs in the Regional NSR Holding Account would be 0.827 tons per day for 2023 & beyond (See Appendix U). These RTCs would be derive d from the RTC reductions applied to the newer electrical electricity generating facilities listed in Table 9. 

## Rule 2002 (i) – RTC Reduction Exemption
Given that no facilities in the history of the RECLAIM program have applied for an exemption pursuant to subdivision (i), and given the unlik elihood that a facility co uld meet the stringent requirements listed therein, sta ff is proposing to remove the subdivision in its entirety. .

### 44 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Rule 2002 (i) – Facility and Equipment Shutdowns
The proposed rule includes provision to address the retirement of RTCs from complete facility closure or equipment shutdowns that represent twenty-five percent or more of a facility’s emissions for any quarter within the previous 2 compliance years. This would apply to any facility listed in Table 7 or 8 of Rule 2002. Permits associated with the equipment being shut down would be surrendered, and the RTCs for future years would be retired from the RECLAIM program. 

## Rule 2005 – Requirements for New Electrical Electricity Generating Facilities
Rule 2005 sets forth requirements for new or modified equipment or processes at RECLAIM facilities. The purpose of the rule is to ensure that the RECLAIM program is equivalent to the federal and state NSR program requirements. One of the requirements is to ensure that the facility must hold sufficient RTCs to offset emission increases for one year prior to commencement of operation and at the beginning of every compliance year thereafter. For an RECLAIM facility existing prior to the adoption of the RECLAIM program, the amendments made in June 3, 2011 required the RECLAIM facility to hold adequate RTCs for the first year of operation prior to commencement of operation of a new or modified source, but will not require the facility to hold RTCs at the commencement of subsequent compliance years, provided that the facility emission level remains below its starting Allocations plus non-tradablecredits. However, a new RECLAIM facility will have to con tinue to hold adequate RT Cs equal to the amount of emission increases at the beginning of each compliance year. Any unu sed RTCs cannot be sold until the end of the compliance year, or the applicable quarters if the facility has permit conditions to cap its emissions during each quarter, thus allowing sale of unused RT Cs at the end of the quarter. To remedy this burdensome RTC holding requirement for new el ectrical generating facilitiesEGFs that cannot change their allowable NOx emissions in their Facility Permit, staff is proposing a Regional NSR Holding Account described in Rules 2002(f)(4) a bove. Proposed changes in Rule 2005 would assure that the RTCs in the Account would only be used the for the purpose of complying with the NSR requirements (other than acce ss during a power crisis as also described in 2002(f)(4)) . Please see Appendix X for fu rther explanations. 

## Other Administrative Amendments

Besides the changes described in Rule 2002 a nd 2005 described above, staff also proposes administrative amendments to Regulation XX to clarify the rule language and to ensure effective and consistent implementati on of the RECLAIM program.

### 45 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Rule 2002(b)(5) - 5-Year Limitation on Amending Annual Emission Reports Some facilities entering the RECLAIM program have sought to amend their past AERs, which dated as far back as 1989, in ways that increasethe initial SOx and/or NOx allocations previously determined pursuant to Rule 2002. The longer the time that has elapsed between the reporting period and the submittal of the amendment, the more problematic the process of validating the proposed changes and the supporting documentation. Infact, such validation has been infeasible in some cases. Therefore, staff is proposing to add language to Rule 2002(b)(5) to provide clarity on which annual report submittals and/or revisions may be considered by staff in determining facility allocations. Rule 2002 (Table 4) – Minor Typographical Edit

Rule 2002’s Table 4 – RECLAIM SOx Tier III E mission Standards includes a row for Diesel Combustion, which includes a BARCT Emission St andard of “15 ppmv as required under Rule 431.2.” However, the standard in Rule 431.2 is ac tually “15 ppm by weight” rather than 15 ppmv ( i.e. , 15 ppm by volume). The staff proposal would co rrect the Table 4 entry to “15 ppm by weight as required under Rule 431.2,” consistent with the definition of Low Sulfur Diesel at Rule 431.2(b)(5).
Rules 2011 and 2012 - Delayed RATA Tests du e to Extenuating Circumstances Rules 2011 and 2012 set forth monitoring, reporting , and recordkeeping requirements for sources of SOx and NOx at RECLAIM facilities. The accompanying Appendices A to these rules outline in greater detail the technical specifications requi red for monitoring, reporting, and recordkeeping for RECLAIM sources such as the timing and freque ncy of Semi-Annual Assessments in the form of Relative Accuracy Test Audits (RATAs) fo r CEMS. RATAs must be conducted while the equipment is in operation. Equipment monitored by CEMS at some RECLAIM facilities, however, may experience extenuating circumstan ces that prevent them from conducting RATA tests in a timely manner. Additionally, facilities under contract with the California Independent System Operator (CalISO), as well as electrical electricity generating facilities owned and operated by municipalities, have experienced difficulties in meeting RATA deadlines because their equipment operates based on current energy demand and may not operate long enough (or at all) to conduct a RATA in the quarter in which RATA is due. Electrical El ectrcity generating facilities with equipment under contract with CalISO or owne d and operated by municipalities often do not know when demand for electricity will result in generation equipment being required to operate until a day prior, creating scheduling difficulties in conducting RATAs and precludi ng the use of non-operational

### 46 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

status. The inherent inconsiste nt operational nature of such e quipment at electric generating facilities sometimes causes a needto postpone their RATAs. Under current rule requirements, facilities having such extenuating circumstances seek variances for indeterminate amounts of time. The proposed amendments would, under specific conditions and criteria, allow RECLAIM Facility Permit Holders of equipment experiencing these extenuating circumstances to postpone RATAs. Th e specific conditions and criteria are further explained in details in Appendix X.
Proposed Amended Rules 2011, Appendix A, AttachmentE and 2012, Appendix A, Attachment F – Clarification of “Standard Gas Conditions” Proposed amendments to Rule 2011, Appendi x A, Attachment E and 2012 Appendix A, Attachment F would clarify standard gas conditions by giving each facility operator the option to use either the 60 oF standard or the 68 oF standard provided one or the other is used consistently throughout the facility for RECLAIM purposes.
Rules 2011 and 2012 - Typographical Edits Staff also proposes to make several typographical clarifications and corrections in Rules 2011 and 2012 Appendix A, Attachment C B.2.b and Rule 2011 Appendix A, Attachment C B.2.e. Please see Appendix X for fu rther explanations. 

## Draft Program Environmental Assessment (PEA)
A Notice of Preparation/Initial Study (NOP/IS) was released for a 57-day public review and comment period from December 5, 2014 to January 30, 2015. Eight comment letters were received from the public regarding the preliminary an alysis in the NOP/IS. These comment letters and responses to individual comments are in cluded in Appendix G of the Draft Program Environmental Assessment (PEA). In addition, on January 8, 2015, a CEQA and Socioeconomic Scoping Meeting was held. CEQA comments rais ed at the Scoping Meeting have been summarized and responded to in Appendix H of the Draft PEA. Socioeconomic comments raised at the Scoping Meeting and in the two comment letters specific to socioeconomic issues received are addressed in the Draft Socioeconomic Analysis. The Draft PEA was released on August 13, 2015, and the commenting period was extended un til October 6, 2015. The Draft Socioeconomic Analysis was released on September 9, 2015.

### 47 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Draft Findings under California Health and Safety Code

California Health and Safe ty Code § 40727 requires that prior to adopting, amending or repealing a rule or regulation, the AQMD Governing Board sh all make findings of necessity, authority, clarity, consistency, non-duplication, and referenc e based on relevant inform ation presented at the public hearing and in the staff report. Necessity A need exists to amend Rules 2002 – Applicability, 2002 – Allocations for Oxides of Nitrogen (NOx) and Oxides of Sulfur (SOx), 2005 – New Source Review for RECLAIM, 2011 – Requirements for Monitoring, Re porting, and Recordkeeping for Oxides of Sulfur (SOx) Emissions (Protocol), and 2012 – Requirements fo r Monitoring, Reporting, and Recordkeeping for Oxides of Nitrogen (NOx) Emissions (Protocol) to seek additional emission reductions from RECLAIM relative to the 2012 AQMP (Control Measure CMB-01), to demonstrate BARCT equivalence pursuant to Calif ornia Health and Safety C ode §40440, and to make changes necessary for the ongoing administration of the program. Authority The AQMD Governing Board has authority to amend existing Rules 2001 – Applicability, 2002 – Allocations for Oxides of Nitrogen (NOx) and Ox ides of Sulfur (SOx), 2005 – New Source Review for RECLAIM, 2011 – Requirements for Monitoring , Reporting, and Recordkeeping for Oxides of Sulfur (SOx) Emissions (Protocol), and 2012 – Requirements for Monitoring, Reporting, and Recordkeeping for Oxides of Nitrogen (NOx) Emissions (Protocol), pursuant to California Health and Safety Code §§ 39002, 40000, 40001, 40440, 40440.1, and 40702. Clarity The proposed amended rules are written or displayed so that their meaning can be easily understood by the persons directly affected by them.
Consistency The proposed amended rules are in harmony with and not in conflict withor contradictory to, existing statutes, court decisions or state or federal regulations. Non-Duplication The proposed amended rules will not impose the samerequirements as any existing state or federal regulations. The amendments are necessary and proper to execute the powers and duties granted to, and imposed upon, AQMD.

### 48 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Reference By adopting the proposed amended rules, the AQMD Governing Board will be implementing, interpreting and making specific the provisions of the California Health and Safety Code §§ 39002, 40001, 40440 (a), 40440.1, 40702, and 40725 through 40728.5; and Title 42 U. S. C. Sections 7410 and 7511a. Comparative Analysis H&S Code §§ 40727 and 40727.2 require a written analysis comparing the proposed amended rule with existing regulations. The §40727.2 analysis is traditionally applied to source-specific rules requirements affecting equipmen t subject to a command-and-c ontrol regulatory approach. RECLAIM varies from this regulatory approach in that it is based on a mass cap approach with a declining balance. This regulatory program decreases emission credit holdings, which caps emissions at a facility, as opposed to application of equipment-specific requirements. Therefore, this comparative analysis differs from the traditional comparative analysis. A comparative analysis for the RECLAIM program was provided for Rule 2002, amended on January 7, 2005 (NOx RECLAIM sources) and November 5, 2010 (SOx RECLAIM sources). A comparative analysis, as required by H& S Code §40727.2, compares individual pieces of equipment to any applicable standard. The key to this analysis is to demonstrate non-duplication of new or amended regulatory requirements onan affected source. The current proposed RECLAIM amendment primarily seeks to reduce RT Cs in the market and NOx emissions. There are no significant changes proposed to the other pr ogram elements, such as enforceable procedures, operating parameters or work prac tice requirements. In addition, amendments to the monitoring, recordkeeping, and reporting requirements are admin istrative in nature, as they do not affect or otherwise change an emissions limitation or add a significant requirement. On this basis, this comparative analysis focuses only on the determination of a new BARCT standard for the equipment under RECLAIM.

Relative to the derivation of new BARCT standards, all of the equi pment categories listed in Tables 1 and 3 of Rule 2002 were examined by staff an d presented to stakeholders for comments and feedback. However, as shown in Table 3.1 of th is staff report, new BA RCT was only determined for fluid catalytic cracking units, refinery boilers and heaters greater than 40 million British thermal units per hour (mmbtu/hr), refinery gas turbines, coke calci ner, sulfur recovery units/tail gas incinerators, cement kilns, container glas s melting furnaces, sodium silicate furnace, heat treating furnaces greater than 150 mmbtu/hr, non-re finery gas turbines, and internal combustion engines. In making the BARCT determinations , as discussed in Appendices A through S, a systematic approach of analysis was undertaken to de rive any new control standards. This analysis included review of potentially applicable require ments from other air pollution control districts or agencies, applicable AQMD rules, as well as emission controls achieved in practice or otherwise

### 49 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 technologically and economically feasible that would have otherwise been required under a command-and-control regulatory approach in the absence of RECLAIM. The results of the BARCT analysis are presented by equipment category in Appendices A through S. The proposed programmatic reduc tions are based on the determination of new BARCT for certain emission sources. The resulting equi pment-level reductions that w ould have occurred if applied with the same percentage under a command-and-c ontrol regulatory program are subsumed and spread among the RECLAIM facilities which hold 90 percent of the RECLAIM Trading Credits (RTC). The RTCs are proposed to be reduced at a rate of 66 percent for the larger refineries and investors and 49 percent among the remaining facilities that comprise those facilities holding 90 percent of the RTCs. As RECLAIM is a market-based program with facility-level mass emissions caps there are no specific air pollution control requirements (i.e., equipment specific emission limits) for these sources that must be met by these RECLAIM facilities holding 90 percent of the RTCs. Facilities are allowed the flexibility to meet their reduction requirements by whatever means they choose, such as equipment modifi cations, installation of control equipment, or purchasing RTCs. Notwithstanding the aforementioned discussion, RECLAIM facilities are subject to the requirements of other AQMD regu lations not subsumed by the program, including requirements under Regulation II – Permits, and Regulation IV – Prohibitions, such as Rule 401 – Visible Emissions, Rule 402 – Nuisances, and Rule 403 – Fug itive Dust. It should be noted that there are federally mandated programs, such as New Source Review (BACT/LAER), Prevention of Significant Deterioration, and St andards of Performance for New Stationary Sources, which are also applicable to the RECLAIM program and incorporated within the program. RECLAIM also complies with federal policy regarding start-up, sh utdown, and malfunctions. In addition, there is not a comparable state or federal program for a cap and declining balance of NOx emissions. However, RECLAIM, as it currently exists, is in the SIP and complies with federal requirements applicable to market-type air pollution control programs, such as the Economic Incentive Program (EIP) guidelines. Consequently, RECLAIM stands on-its-own and doe s not contain any duplicative or conflicting regulatory requirements. 

## Incremental Cost-Effectiveness Health and Safety Code Section 40920.6 requires anincremental cost-effectiveness analysis for Best Available Retrofit Control Technology (BARCT ) rules or emission reduction strategies when there is more than one control option that woul d achieve the emission reduction objective of the proposed amendments, relative to NOx. The proposedcontrol option is what was analyzed in the BARCT analysis, while the alternative control option is BARCT control to a less stringent level.

### 50 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
To determine the incremental cost effectiveness, the calculated difference in the dollar cost between the two control options is divided by th e difference in their emi ssion reduction potentials. The control costs for the staff proposal used the average cumulative present worth values for each source category. The control costs for the alternative project used the same costs for the control equipment because it is assumed that a majority of the same costs to build and construct a control system despite a higher emission level would still apply. The emission reductions of the alternative project are calculated by using the higher BARCT level applied to each source category. The emission re ductions of the proposed control option are also factored into the final calculation. The difference of the PWV of the alternative co ntrol option and the proposed control option (the PWV is the same in this case) is divided by th e difference in the emission reduction potentials for both projects. If “a” is the alternative control option and “p” is the proposed control option, then the incremental cost effectiveness is:

(C a – C p ) / (E a – Ep ) = $ costs /per ton

When calculated across all the source categorie s subject to BARCT for NOx RECLAIM, the incremental cost effectiveness for the source categories ranged from $53,000/ton to $917,000/ton. The table below lists the incremental cost effec tiveness values calculated for all the source categories subject to the BARCT analysis.

### 51 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015



### Source Category Incremental Cost Effectiveness ($/ton) FCCUs $117,000 Refinery Gas Turbines $60,000 Boilers/Heaters >40 MMBTU/hr $61,000 Coke Calciner $897,000 SRU/TG Incinerators $63,000 Container Glass Melting Furnaces $78,000 Sodium Silicate Furnace $122,000 Metal Heat Treating Furnace >150 MMBTU/hr $61,000
Non-Refinery, Non-Electrical Electrcity Generating Facility Gas Turbines $917,000
Non-Refinery, Non-Electrical Electrcity Generating Facility IC Engines $53,000

The calculated values clearly indicate that the alternative control option is not viable when compared to the proposed controls.

### 52 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Part I – BARCT Analyses for Refinery Sector
Part I contains the information related to the BARCT analyses for the refinery sector. Part I includes 10 Appendices from Appendix A to Appe ndix J that discuss 1) the NOx control technologies, 2) costs and cost effectiveness anal yses for major NOx source s at the refineries, and 3) the consultant’s analyses. The NOx reductions co-benefits of the energy efficiency projects at the refineries are summarized in Appendix K. The Su rvey Questionnaires sent to the refineries in 2003 2013 to collect pertinent information for this BARCT analyses are included in Appendix L.

### 53 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix A - Refinery Fluid Catalytic Cracking Units Process Description

There are five refineries that operate six fluid catalytic cracking units (FCCU) in the SCAQMD: Chevron, ExxonMobil, Tesoro (Carson and Wilmin gton), Phillips66, and Valero. The FCCUs are classified as major sources of emissions in RECLAIM, and as such, the NOx emissions from FCCUs are required to be monitored with a con tinuous emission monitoring system (CEMS), and reported on a daily basis electronically to the SC AQMD. A brief description of the process is presented below. An FCCU converts heavy oils into more valuablegasoline and lighter pr oducts. A schematic of the process is shown in Figure A.1. The process us es a very fine catalyst that behaves as a fluid when aerated with a vapor. The fluidized catalyst is ci rculated continuously between a reactor and a regenerator and acts as a vehicle to transfer heat from the regenerator to the oil feed in the reactor. The cracking reaction is endothermic and the rege neration reaction is exothe rmic. The fresh feed is preheated by heat exchangers to a temperature of 500-800 degrees Fahrenheit and enters the FCCU at the base of the feed riser where it is mixed with the hot regenerated catalyst. The heat from the catalyst vaporizes the feed and raises it to the desired reaction temperature. The mixture of catalyst and hydrocarbon vapor travels up the riser into the reactor. The cracking reaction starts in the feed riser and continues in the reactor. Average reactor temperatures are in the range of 900- 1,000 degrees Fahrenheit. As the cracking reaction progresses, the catalyst surface is gradually coated with carbon (coke), reducing its effici ency. While the cracked hydrocarbon vapors are routed overhead to a distillation column for separa tion into lighter components, the oil remaining on the catalyst is removed by steam stripping before the spent catalyst is cycled to the regenerator. In the regenerator, spent catalyst is reactivated (regenerated) by burning the coke off the catalyst surface. The regenerated catalyst is generally st eam-stripped to remove adsorbed oxygen before being cycled back to the reactor. The regenerator exit temperatures for catalyst are about 1,200- 1,450 degrees Fahrenheit. The regenerator can be de signed and operated to either partially burn the coke on the catalyst to a mixture of carbon monoxide (CO) and carbon dioxide (CO 2 ), or completely burn the coke to CO 2 . The regenerator temperature is carefully controlled to prevent catalyst deactivation by overheating and to providethe desired amount of carbon burn-off. This is done by controlling the air flow to give a desired CO 2/CO ratio in the exit flue gases or the desired temperature in the regenerator. The flue ga s containing a high level of CO is routed to a supplemental-fuel fired CO boiler if need ed to completely burn off the CO to CO 2 . The FCCUs in the SCAQMD are currently operated in a completely burn mode; what used to be the CO boilers are used as heat recovery devices without any supplemental fuel.

### 54 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 It is during the regeneration cycle that some of the catalyst is lost in the form of catalyst fines, and NOx, SOx and other pollutants are formed. The FCCUis a major source of sulfur oxides (SOx), nitrogen oxides (NOx), particulate matter (PM 10, PM2.5), as well as ammonia (NH3), hydrogen cyanide (HCN) and other pollutants in the refi nery. Approximately 90% of the NOx generated from the FCCUs are from the nitrogen in the feed th at is accumulated in the coke which is then burned-off in the regenerator. This portion of th e NOx is called “fuel” NOx. “Fuel” NOx is a combination of nitric oxide (NO), nitrogen dioxide (NO 2 ), and nitrous oxide (N 2 O). The remaining 10% of the NOx generated from the FCCUs are “thermal” NOx which is generated in the high temperature zones in the regenerator, and “p rompt” NOx generated from the reaction between nitrogen and oxygen in the combustion air. The NOx emissions from the FCCU are typically controlled with selective catal ytic reduction (SCR), LoTOx sc rubbers, and/or NOx reducing additives.

Feed from Crude Unit Reactor

Catalysts Recirculation Electrostatic Precipitator

(ESP)* or Scrubber Regenerator

Selective Catalytic Reduction

(SCR)*
Combustion Air Hydrocarbon Products to Main Fractionation Column

NH 3

Steam NO, HCN, N 2 SO 2 , PM2.5, and others

* SCR and WHB are

Waste Heat Boiler (WHB)*

located either Catalyst Fines before or after ESP Figure A. 1 - Simplified Schematic of FCCU Process 

## Emission Inventory

As shown in Table A.1, the total 2011 NOx emissi ons from the six FCCUs (two with downstream CO boilers/heat exchangers) located inthe SCAQMD are 1.08 tons per day. Three FCCUs at Refinery 6, 1 and 5 use SCRs installed in 2000, 2003 and 2008, respectively to control NOx emissions. Three FCCUs at Re finery 4, 7 and 9 have no NOx controls. As shown in Table A.1, Refinery 1’s FCCU w ith SCR currently emits at a level under 2 ppmv NOx (with a 5 ppmv ammonia slip.) The NOx c oncentrations from other FCCU/CO units vary from 6 to 45 ppmv. Figure A.2 graphically show s the 2011 NOx emissions and the regenerator

### 55 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 exhaust gas NOx concentrations for the six FCCUs in the SCAQMD. Comparing the data of the six FCCUs, Refinery 1’s FCCUoperating with SCR installed in 2003 has the lowest NOx emissions and the lowest NOx concentrations at below 2 ppmv. As previously mentioned, 90% of the NOx emissions from the FCCUs are generated from the nitrogen in the FCCU feed (or coke in the re generator.) Figure A.3 shows the NOx emissions compared to the FCCU feed rates. Comparing the data of the six FCCUs, Refinery 1 has the highest feed rate but achieves the lowest emissions with the use of an SCR.
Table A. 1 - 2011 Emissions for Refinery FCCUs
Facility ID Device ID Device Process/NOx Control 2011 Emissions (lbs) Current NOx ppmv @ 3% O2 5 203 REGEN1 FCCU/SCR 119,724 14.84 1 164 REGEN2 FCCU/SCR 16,686 1.21 6 151 REGEN3 FCCU/SCR 123,008 5.62 6 164 CO BOILER FCCU/SCR 20,038 5.62 4 112 CO BOILER FCCU/no control 157,150 21.0 - 27.6 4 96 REGEN4 FCCU/no control in CO Boiler 21.00 7 1 REGEN5 FCCU/no control 101,648 12.88 9 36 REGEN6 FCCU/no control 249,277 35.5 - 45 Total 1.08 tons per day 

## Achieved-In-Practice Level for FCCU
Refinery 1 FCCU’s SCR has demonstrated that a level of 2 ppmv NOx at 5 ppmv ammonia slip is achieved in practice. Reference 1

 The SCR was installed and operated since 2003. It was designed with a NOx inlet of 155 ppmv

to achieve a level of 10 ppmv NOx outlet concentration (>90% control efficiency)

 At normal operations, the inlet NOx concentrations range from 40 - 80 ppmv, and the outlet

NOx concentrations are typically below 2 ppmvwith 5 ppmv ammonia slip (95% - 98% control efficiency). The SCR is capable of having three catalyst layers, each 29 ft x 29 ft x 4.5 ft deep; and is operated with two layers to reach 95% - 98% control. Catalyst life is 5 to 6 years.40 Draft Final Staff Report – NOx RECLAIM 

### 56 October 6November December 4, 2015

NOx Concentration 2011 NOx Emissions
0.4

35 0.35

30 0.3

25 0.25

20 0.2

15 0.15

10 0.1

5 0.05

0 Refinery 4 Refinery 9 Refinery 7 Refinery 5 Refinery 6 Refinery 1 No Control No Control No Control SCR 2008 SCR 2000 SCR 2003 Achieved in Practice = 2 ppmv NOx (with 5 ppmv NH3 Slip) Figure A. 2 - 2011 NOx Emissions and NOx Concentrations for Refinery FCCUs2011 Emissions (tons per day)NOx Concentration (ppmv)

Figure A. 3 - 2011 NOx Emissions and Feed Rates for Refinery FCCUs

### 57 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Control Technology
The commercially available control tec hnologies for NOx are discussed below.
Selective Catalytic Reduction (SCR) For the past two decades, SCR technology has beenused successfully to control NOx emissions. The technology is considered mature and commerciall y available. SCRs can be designed to reduce 95%-98% NOx emissions from the FCCUs and ac hieve 2 ppmv NOx while maintaining a low ammonia slip of less than 5 ppmv. 1-17

SCR is an effective control technol ogy for NOx which uses ammonia (NH 3 ) to selectively reduce NOx to nitrogen through the following reactions: 2 - 4

4 NH 3 12ĺ1 2 + 6 H 2 O (Reaction 1) 4 NH 3 + 2 NO + 2 NO 2 ĺ1 2 + 6 H 2 O (Reaction 2) It should be noted that, at temperatures above 797 o F, ammonia can be oxidized to form NO and N 2 O. These are undesirable reactions since NO and N 2 O will ultimately convert to NOx and increase the NOx emissions. 5

4 NH 3 + 5 O 2 ĺ12 + 6 H 2 O (Reaction 3) 4 NH 3 + 4 NO + 3 O 2 ĺ1 2 O + 6 H 2 O (Reaction 4) A successful SCR catalyst can facilitate the reduction of NH 3 (Reaction 1 and 2) while subsiding the NH 3 oxidation reactions (Reaction 3 and 4). Typically, the SCR catalysts are vanadium, titanium, and/or zeolite based with different sizes and shapes, and have various ranges of operating temperatures: 5 – 8, 18
Conventional SCR catalysts: 400 degrees F - 800 degrees F Low temperature SCR catalysts: 300 degrees F - 400 degrees F High temperature SCR catalysts: 800 degrees F - 1100 degrees F

The stochiometricstoichiom etric amount of ammonia required is 1 mole of NH 3 per mole of NOx reduced (NH 3 /NOx = 1). Ammonia injection and mixing are critical since a non-uniform distribution and mixing of ammonia can result in inadequate NOx c onversion and extensive ammonia slip. To reduce the ammonia slip caused by imperfect ammonia distribution and mixing, SCR manufacturers have developed the Am monia Slip Catalyst (ASC), a layer of catalyst which can be

### 58 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 installed downstream of the SCR catalyst. Early generation of ASCs werebased on precious metal which is highly active for NH 3 oxidation. The current newly de veloped ASCs selectively favor the NH 3 reduction over the NH 3 oxidation: NH 3 is partially oxidized to NO (Reaction 3) and NO is then quickly reduced to N 2 (Reaction 1 and 2). In addition, the advanced ACSs highly support the oxidation of CO to CO 2 . Other advantages of ASCs are summarized below: 5, 9-10

 Enhancing the selective reduction of NO to N2 and supporting the oxidation of CO to CO2 while suppressing the oxidation of NH3 to NOx;

 Allowing for operations at higher NH 3 /NOx ratios to ensure complete NOx conversion;

 Maintaining low ammonia slips; and

 Reducing the overall SCR catalyst volume while maintaining the high NOx control efficiency. In the SCAQMD, aqueous ammonia is required to be used with SCRs instead of anhydrous ammonia due to safety reasons. In general, aque ous ammonia has lower risk s and higher operating costs than anhydrous ammonia. A larger volume of aqueous ammonia will be required to achieve the same NOx reduction, thus increasing the costs of deliveries (e.g. for 29% aqueous ammonia, the delivery costs is in transporting 71% water with the ammonia.) Aqueous ammonia requires either compressed air for atomizati on or vaporizers to evaporate the water. The costs for operating with aqueous ammonia are approximately two times higher than the costs for operating with anhydrous ammonia. 11-13
Sulfur dioxide (SO 2 ) to sulfur trioxide (SO 3 ) conversion and ammonium bisulfate (ABS) formation are undesirable reactions in the SCR process. SO 3 and ABS can cause plugging at downstream components. However, the main factors affecting the formation of ABS, such as temperature, the amount of ammonia slip, molar ra tio of ammonia to NOx, the SO 3 concentrations, and fly ash contents; and the methods to control SO 3 ABS formation to reduce its negative effects have been well investigated, documented, and implemented by the SCR manufacturers as well as the SCR users. In addition, ABS is unlikely to be a problem for low flue gas sulfur units. 14

LoTOx TM Application with Scrubber

LoTOx TM stands for “Low Temperature Oxidation” pr ocess in which ozone is used to oxidize insoluble NOx compounds to soluble NOx compounds. These soluble compounds can then be removed by absorption in caustic so lution, lime or limestone. The LoTOx TM process is a low temperature operating system, optimally operating in a range of 140 - 325 degrees F. The LoTOx TM is a registered trademark of Linde LLC. (p reviously BOC Gases) and was later licensed to BELCO of Dupont for refinery applications. The LoTOx application is explained below. 19 - 27

### 59 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 A typical combustion process produces about 95% NO and 5% NO 2 . Both NO and NO 2 are relatively insoluble in aqueous solution, and thus a wet gas scrubber is not efficient in removing these insoluble compounds from the flue gas stre am. However, with the introduction of ozone, NO and NO 2 can be easily oxidized to highly soluble compounds N 2 O 5 (Reaction 5 and 6) and subsequently converted to nitric acid HNO 3 (Reaction 7). The nitric acid is then rapidly absorbed in caustic solution (Reaction 8), limestone or lime (Reaction 9 and 10), and removed from the wet scrubbers. In addition, the rates of oxidizing reactions for NOx (Reaction 5 and 6) are fast compared to SO 2 oxidation reaction (Reaction 11), and as a result, there is no ABS or SO 3 formation. The LoTOx process can be integrated with any types of wet sc rubbers (e.g. venturi, packed beds), semi-dry scrubbers, or we t electrostatic precipitators (ESPs).

NO + O 3 ĺ12 2 + O 2 (Reaction 5 - Fast) 2 NO 2 + O 3 ĺ1 2 O 5 + O 2 (Reaction 6 – Fast) N 2 O 5 + H 2 2ĺ+12 3 (Reaction 7) HNO 3 1D2+ĺ1D12 3 + H 2 O (Reaction 8) +12&D&2ĺ&D12 3 ) 2 + H 2 O + CO 2 (Reaction 9) +12&D2+ĺ&D12 3 ) 2 + 2H 2 O (Reaction 10) SO 2 + O 3 ĺ62 3 + O 2 (Reaction 11 - Very slow) The LoTOx process requires oxygen supply and ozone generation. Oxygen is used to generate ozone on site. Typically oxygen is stored as liqui d in vacuum jacketed vessels or is delivered by pipeline. Ozone is an unstable gas and it is typically generated on demand using an ozone generator. An ozone generator is shaped similar to a shell and tube heat exchanger. A corona discharge is used to dissociate oxygen into indi vidual atoms; and the oxygen atoms combine with other oxygen molecules to form ozone. An ozone injection manifold should be designed to achieve uniform distribution and complete mixing. A ratio of NOx/O 3 of about 1.75 – 2.5 is needed to achieve 90% to 95% NOx convers ion and reduction. Since sulfit es are ozone scavengers, the LoTOx process typically has a very low ozone slip of 0-3 ppmv. Several advantages of LoTOx appli cation in comparison to SCR are:

 LoTOx is a low temperature operating system, me aning that it does not require heat input to maintain operational efficiency and enables maximum heat recovery of high temperature combustion gases.

 LoTOx can be an integrally connected to a wet (or semi-wet) scrubber, and become a multicomponent air pollution control system that can reduce NOx, SOx and PM in one system whereas SCR is primarily designed to reduce only NOx

 There is no ammonia slip, SO 3 , and ABS issues associated with LoTOx application.

### 60 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

BOC Gases received a grant funded partially by the California Air Resources Board to demonstrate the LoTOx technology at a reverbertory furnace us ed for lead smelting, operated by Quemetco Inc., City of Industry in California. The demonstr ation was successful, accomplishing > 90 percent NOx removal which led to a full scale system installation in 2001. 23 Today, there are more than 50 applications engineered by Linde since 1997, 19 and more than two dozen applications with EDV TM scrubbers engineered by BELCO since 2007. 26 EDV TM is a registered trademark of BELCO. LoTOx with EDV TM scrubber is shown in Figure A.4. Table A.2 contains a list of the LoTOx applicat ions for FCCUs, boilers, furnaces, and other combustion equipment. This is not an inclusive list. Applications in gas-fired and high sulfur coal-fired units met 95% control (2 ppmv - 5 ppmv) . Current installations in refineries have achieved NOx level of 8 ppmv -10 ppmv (85% - 95% control efficiency). Manufacturers have confirmed that LoTOx can be designed to achie ve 2 ppmv NOx from current inlet concentrations (85%-95% control efficiency) for FCCUs.

Figure A. 4 - EDV Scrubber with LoTOx Application

### 61 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table A. 2 – List of LoTOx Applications

% NOx Exhaust Gas NOx Inlet Startup No Application Outlet Control Flow (scfm) (ppmv) Date (ppmv) 1 400 HP natural gas fired boiler * 4,000 30-70 2 97% 1997-98 2 Stainless steel pickling 4,000 3400 100 97% 2000 3 25 MW coal fired boilers 90,000 200 10-20 95% 2001 4 Lead recovery furnace 26,000 50-150 10 93% 2002 5 1000 HP natural gas fired boiler * 10,000 20-40 4 90% 2001 40,000- 80% 6-10 Five (5) FCCUs in the U.S. 70-120 8-20 2007 260,000 11-12 Sulfuric acid plants in the U.S. 2 x 16,800 90 10 90% 2008 Nine (9) FCCUs and 2 LoTOx 12,000 – 93% 13-23 30-250 10-18.5 2008-15 ready installations in the U.S. 310,000 Ten (10) FCCUs, a refinery 80% 90,000- 24-40 boiler, 6 LoTOx ready 100-350 20-73 2012-15 390,000 installations in China 43,000- 80% 41-42 FCCUs in Thailand & Romania 230-250 20-73 2015-19 135,000 Note: See Reference 19. * Units are in Southern California.

NOx Reduction Additives The combustion in the FCCU regenerator gene rates a dozen of various pollutants (NO, N 2 O, NO 2 , HCN, NH 3 , CO, SO 2 etcetc.) and the dynamic interaction of these compounds with each other is complex. A simplified version of the chemical reactions in the FCCU regenerator is shown in Figure A.5. “Fuel” nitrogen in the coke is fi rst converted to HCN. HCN is thermodynamically unstable and it is converted to NH 3 , N 2 , NO, N2O, NO 2 compounds. The rates of these reactions depend heavily on the regenerator temperatures and the regenerator configuration. NOx reduction additives can be used to promote the conversion of NOx, HCN, and NH 3 to N 2 and reduce NOx emissions. The removal efficiency for NOx Reduction Additives is reported to vary from 50% to 80%. 28-38

### 62 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

No Application Capacity (bpsd) NOx Inlet (ppmv) NOx Outlet (ppmv) % Control Startup Date 1 FCCU, Arkansas 20,000 70-100 10 86% 2007 2 FCCU, Texas City, TX 130,000 100-200 10 95% 2007 3 FCCU, Texas City, TX, retrofit 60,000 100-150 8 95% 2007 4 FCCU, Texas City, TX, retrofit 52,000 70-100 10 90% 2007 5 FCCU, Houston, TX, retrofit 58,000 100-150 10 93% 2007 7 8 FCCU, St. Charles, LA, retrofit FCCU, Corpus Christi, TX, retrofit 100,000 45,000 Confidential 2010 2010 9 FCCU, Delaware, DE, retrofit 75,000 TBD 10 FCCU, El Dorado, KS 40,000 150 20 86% TBD 11 12 FCCU, Ardmore, Oklahoma FCCU, Three Rivers, Texas 40,000 28,000 TBD TBD TBD 13 FCCU, Placid Refining, LA 30,000 TBD Note: Refer to Reference 20 for additional installations inside and outside of the U.S. Some scrubbers have built in ready for LoTOx retrofit but ozone generators have not yet been installed as of May 2013.
Manufacturers of the NOx reduction additives such as BASF, INTERCAT and Grace Davidson recommended the following best practices to minimize the NOx formation with the use of their additives, and at the same time, promote the conversion of CO to CO2:

 Minimizing excess oxygen,

 Reducing feed nitrogen, and

 Utilizing non-platinum CO promoters Figure A.6 shows outlet NOx concentrations of a FCCU with and without the use of NOx Reduction Additives. Data in Figure A.6 shows that higher excess oxygen favors the formation of NOx rather than N 2 , and NOx Reducing Additives are capable of removing 60% of NOx emissions. NOx Reduction Additives cannot yet reduce NOx to 2 ppmv levels, however additives may be used in combination with other control tec hnologies to reach the targeted levels. Two manufacturers indicated that NOx additives generally would cost about $15-$20 per pound and would be used at a rate between 1-3% of the F CC fresh catalyst addition rate. The NOx control effectiveness of the NOx Reducing Additives would be very specific for each FCCU application.

### 63 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

(Picture taken from References 22 and 23) Figure A. 5 - Nitrogen Chemistry in the FCC Regenerator

180

160

140

120 NO ADDITIVE
100

80

60

40 WITH ADDITIVE 20

0 0.0 0.5 1.0 1.5 2.0 2.5 O2, % (Picture taken from Reference 22) Figure A. 6 - NOx Reduction Additi ve Reduces NOx Emissions by 60%NOx, ppm

### 64 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015



## Costs and Cost Effectiveness for SCRs
Several methodologies were used to estimate the costs and en suing cost effectiveness of installing or modifying the SCR’s for the FCCU controls to 2 ppmv NOx. These included direct cost estimates from refiners, scaling cost estimates based on flue gas flow rates, using U.S. EPA’s guideline approach, an upper range industry cost fa ctor and a consultant’s independent assessment. Refinery 1 The refinery 1 SCR achieved 2 ppmv NOx and 5 ppm v NH3 slip. Refinery 1 provided staff with the total installed costs, ammonia costs, and catalysts replacement costs for their SCR. 1 Staff estimated Present Worth Value (PWV) for Refinery 1 SCR using the equations below assuming 4% interest rate and 25-years SCR life. The PWV of Refinery 1 SCR was estimated to be $41 million dollars.

PWV Ref 1 = TIC Ref 1 + (15.62 x AC Ref 1 ) + (2.52 x CR Ref 1 ) (Equation 1) Where: PWV Ref 1 = Present Worth Value, $ TIC Ref 1 = Total Installed Costs, $ AC Ref 1 = Annual Operating Costs, $ CR Ref 1 = Catalysts Replacement Costs, $ Refinery 5, 6 and 7
Costs for the SCRs at Refineries 5, 6 and 7 were derived based on Refine ry 1’s data. The PWV of Refinery 5, 6, and 7 SCRs were estimated using the PWV of Refinery 1 SCR and the ratios of their appropriate inlet flue gas flow rates to the 0.7 power as follows. The PWVs of SCRs for Refinery 5, 6 and 7 were es timated to be $33 million, $57 million and $27 million respectively as shown in Table A.3.

PWV Ref 5 = PWV Ref 1 x (Flow Rate Ref 5 / Flow Rate Ref 1 ) ^0.7 (Equation 2) PWV Ref 6 = PWV Ref 1 x (Flow Rate Ref 6 / Flow Rate Ref 1 ) ^0.7 PWV Ref 7 = PWV Ref 1 x (Flow Rate Ref 7 / Flow Rate Ref 1 ) ^0.7

Refineries 5 and 6 installed their SCRs in 2008 and 2000 respectively. In order to meet the 2 ppmv NOx proposed level, they may choose to 1) retr ofit their existing SCRs, or 2) add additional catalysts to their existing SCRs if space is availabl e (Note: Refinery 1 only utilizes 2 layers out of 3 layers of catalysts to meet 95% - 98% control), or 3) change the existing catalysts to a more

### 65 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 effective catalyst type. As shown in Table A.3, the PWVs in these scenarios can be potentially less than $33 million and $57 million dollars for Refineries 5 and 6, respectively.
Refinery 4 and 9 Refinery 4 and Refinery 9 FCCU s have no controls for NOx em issions. Several manufacturers provided costs information for th e SCRs at Refinery 4 and Refinery 9 to achieve 2 ppmv and 5

- ppmv NOx. 15 17 One manufacturer indicated that the flue gas exist temperatures at the two refineries must be raised to 650 degrees F to avoid SO2/SO3 and AB S related problems; and estimated that this would a dd about 10% to the overall costs of the equipment. The EPA’s OAQPS Guidelines’ approach was used to estimate the following costs: 4
Instrumental = 10% x Equipment Cost Sales Tax = 9% x Equipment Cost Freight = 5% x Equipment Cost Thus, Total Equipment Cost = 1.24 x Equipment Cost = 1.24 EC Installed Costs = 50% of Total Equipment Costs
Total Installed Costs (TIC) = (1.24 EC ) + 0.5(1.24 EC) = 1.86 EC (Equation 3) Based on its reported data, the annual operating costs of Refinery 1’s SCR during its 25-year life is about 20% of the total installe d costs. Staff used this 20% factor to estimate the 25-year operating costs for the new SCRs at all the refineri es. Staff added a contingency factor of 1.5 to cover additional uncertaintie s for both the TIC and the annual operating costs.

PWV Ref 4, Ref 9 = 1.5 [(1.86 EC) + 0.2 (1.86 EC)] = 3.35 EC (Equation 4) Using the EPA OAQPS Guidelines’ approach, the PWVs would become $16 million and $19 million for Refinery 4 and 9 as shown in Table A.3, respectively.
Cost effectiveness (CE) was estimated as follows and is summarized in Table A.3: CE = PWV / (ER x 365 days x 25 years) (Equation 5) Where: CE = Cost Effectiveness, $/ton PWV = Present Worth Value, $ ER = Emission Reductions, tpd

### 66 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

The cost effectiveness in Table A.3 is estimate d using Discounted Cash Flow (DCF) method. The cost effectiveness calculated based on the Leveliz ed Cash Flow (LCF) method is about 1.65 times higher than the cost effectiveness estimated by the DCF method (e.g. $18K per ton DCF compared to $30K per ton LCF.)
Table A. 3 - Costs and Cost Effectiveness for SCRs (December 2014)

Fac Emissions NOx % Emission PWV CE ID (tpd) (ppmv) Control Reduction (tpd) ($M) ($/ton)

1 0.02 <2 95% - (41) (10,181) 5 0.16 15 87% 0.14 < 33 < 25,259 6 0.20 6 64% 0.13 < 57 < 49,408 7 0.14 13 84% 0.12 27 25,455 4 0.22 21-23 91% 0.20 16 8,961 9 0.34 34-52 95% 0.32 19 6,537 Total reductions for Ref 4,9,5,6 and 7 0.91 152 Avg <18,422 Emissions for all 6 refineries = 1.08 tpd. Remaining emissions from FCCUs at BARCT for all 6 refineries = 1.08 – 0.91 = 0.17 tpd

Consultant’s Analysis fo r SCRs and Staff’s Revi sed Estimates for SCRs In 2014, staff contracted Norton Engineering Consu ltants (NEC) to conduct a BARCT analysis for the refinery sector. 39 The NEC’s analysis is included in Addendum 1. Table A.4 shows a comparison between NEC’s and staff’s estimates:

Table A. 4 – Comparison of SCR Costs Estimated by Staff and NEC (December 2014)
Facility Staff’s Estimates NEC’s NEC’s Feed Rate ID (note 1) Estimates Adjusted ($M) ($M) Estimates ($M) 5 <33 <46 (note 2) <43 6 <57 <46 (note 2) <50 7 27 42 (note 3) 37 4 16 38 38 9 19 39 37 Total 152 211 195 Note: 1) Staff’s estimates were presented at the Jan 22, 2014 Working Group Meeting. For a 2-layer SCR configuration; 2) Estimates reflect a new SCR installation and are over-estimated because the FCCUs already have SCRs installed; 3) This FCCU will be dismantled.

### 67 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 NEC recommended SCRs with 3 layers of catalyst s compared with staff’s analysis based on refinery FCCU SCR applications currently operating with 2 layers of catalyst in the Basin. The NEC cost estimate included 2 layers of markup factors applied to the equipment costs and an overall 4.5 factor to project the total installe d cost to the cost of material and labor. 6 NEC further added the cost of waste heat boiler modifications, new CEMS a nd additional ammonia storage. The resulting cost information was used to generate a curve to express PWV as a function of feed rate.

NEC’s initial estimation of PWV was conducted using a set of refinery FCCU feed rates that were not consistent with those reported in the 2010 SOx RECLAIM staff report or by the January 22, 2014 RECLAIM Working Group presentation. The third column in Table A.4 provides the adjusted cost estimate to account for the representative refinery feed rates.
Catalyst Layers Staff used a different approach than NEC to estimate the SCR costs because Refinery 1 had achieved an emissions rate of 2 ppmv NOx with onl y 2 layers of catalysts. This resulted in a significant difference in the cost estimates based on 2 catalyst layers (staff) and 3 catalyst layers (NEC). To address this difference, staff adjusted the manufacture’s proposed 60 barrels/day 3 catalyst-layer SCR configuration used by NEC in their estimate to a 2 catalyst-layer model. The adjustment included a 27 percent reduction in the base price to account for the 2-layer configuration (at 10 ft. per second) but thenfollowed NEC’s pricing including the 1.35 bid conditioning factor, the 1.75 labor factor and a 4.5 factor applied to the equipment cost. The adjusted estimate added the costs of the waste heat boiler modifications, additional ammonia storage, added CEMS, maintenance and catalyst replacement costs. The projected PWV for the adjusted manufacturers estimate for the 2-catalyst layer configuration is listed in Table A.5 totaling $163 million for five FCCU’s.
Range of Costs and Cost Effectiveness for SCRs In its report, NEC indicated that the factors inthe EPA OAQPS Guidelines (Equation 3) were not sufficient to cover retrofitting applications at th e refineries. The refineries also indicated the factors relating equipment costs to TIC should be at least 4, or higher. To re concile this difference, staff presents the PWVs as a range of co sts and cost effectiveness in Table A.5.

6 NEC first marked-up the costs provided by the manufacturer by 35%. NEC named this markup as “bid conditioning factor” to cover the “low” bid provided by the manufacturer. NEC then added 75% increase in labor costs to the costs provided by the manufacturer. NEC did not provide any references to their markup factors and simply stated that the factors were based on thei r own experience.

### 68 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The staff cost effectiveness estimate is based on a 2-catalyst layer FCCU SCR application that is operating at Refinery 1. The PWV calculated for the five units totaled $152 million establishing the lower end average of the cost effectiven ess at $18,000 per ton NOx reduced. The upper cost effectiveness listed in Table A.5 is derived from the PWV totals from the manufacturers adjusted 2-layer estimate averaging $20,000 per ton NOx reduced.
As previously stated, the 2-layer catalyst SCR application has been demonstrated to reach 2.0 ppmv at Refinery 1, in the Basin. Since NEC’s proposed model is based on a 3-layer catalyst application it is not included in the cost effe ctiveness calculation presented in Table A.5. Regardless, the cost effectiveness calculated for the NEC model would place the FCCU SCR application for the 5 units at an average CE of $29,000. Thus, using the NEC 3-layer catalyst assumption, the cost effectiveness is still less than the $50,000 threshold used in the current BARCT analysis and less than the $30,800 thres hold established for SCR control equipment established for boilers greater than 75 mmBtu/hr in SCAQMD Rule 1146. Note that Refinery 4’s FCCU is scheduled to be shut down in the near future which would result in lowering the costs estimated for the FCCU category.

Table A. 5 – Revised Costs and Cost Effectiveness for SCRs (March 2015)

Fac ID Emission Red (tpd) Staff’s 2- Layer Estimate

PWV ($M) Manufacturers Adjusted 2- LayerWith no MarkUp Estimates ($M) Manufacturers Ajusted 2- Layer with 2

Mark-Ups Estimates PWV ($M) Range of PWV ($M) CE ($/ton)

5 0.14 <33 <34 <36 <33 – 36 <25K - $27K 6 0.13 <57 <40 <42 <57 – 42 <49K – 36K 7 0.12 27 29 31 27 – 31 25K – 29K 4 0.20 16 22 23 16 – 23 9K – 13K 9 0.32 19 29 31 19 – 31 7K – 11K Total 0.91 152 154 163 152 - 163 18K – 20K


## Costs and Cost Effectiveness for NOx Reduction Additives

NOx reduction additives can reduce about 10% - 70% NOx emissions depending on the FCCU regenerator configuration and operating condition. The use of NOx reducing additives may not achieve the ultimate goal of 2 ppmv, but may help the refineries achieve the future facility overall shave. Cost effectiveness for NOx reducing a dditives were estimated to be about $6,460 per ton

### 69 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 of NOx reduced using DCF method ($10,660 per t on using LCF method.) The inputs and results were summarized in Table A.6. 38

Table A. 6 - Costs and Cost Effect iveness for NOx Reduction Additives
Inputs Baseline NOx 40 ppmv NOx reduction 50% Cost of NOx Reduction Additives $15 per lb NOx Reduction Additives 1.5% of total catalysts Catalyst Addition Rate 4 ton per day FCCU Rate 70 million barrels per day Results NOx Reduction Additives Costs 1800 $/day NOx Reduction 348 lbs/day Cost Effectiveness for NOx Reducing Additives 6,460 $/ton


## Costs and Cost Effectiveness for LoTOx Scrubbers

The FCCUs at Refinery 4 and Refinery 9 currentlyhave no control. Re finery 7’s FCCU has a scrubber. Process data for these three refineries ’ FCCUs were provided to a manufacturer, and the manufacturer provided estimates for the total in stalled costs and annual operating costs. 27
The total installed costs provided by the manufacturer included the ozone generator, the associated closed loop chiller, cooling pump, ozone injection lances. The installed costs also included the associated platforms and access steel, some interconnecting piping and supports, valves and instruments and freight to the job site. The manufacturer did not include oxygen storage and vaporization (which was only necessary if the refinery did not yet have oxygen at the site for other uses), or the cost of electrical equipment and f oundation. Staff added a con tingency factor of 2 to markup the costs provided by the manufacturer to account for any additiona l modifications needed at the site and any variations in annual ope rating costs such as electricity or oxygen. The PWV for Refineries 4, 7 and 9 LoTOx applications were estimated as follows:

PWV Ref 4, 7 and 9 = Contingency Factor x (TIC Ref 4, 7 and 9 + (15.62 x AC Ref 4, 7 and 9 ))

Where: PWV Ref 4, 7 and 9 = Present Worth Value $ TIC Ref 4, 7 and 9 = Total Installed Cost s provided by vendor, $ AC Ref 4, 7 and 9 = Annual Operating Costs provided by vendor, $

### 70 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Contingency Factor = 2 Refineries 5 and 6 currently employ SCRs to re duce their FCCU’s NOx emissions. Scrubbers may be needed to reduce the SOx emissions from their FCCUs, and LoTOx can be installed concurrently with the scrubbers to furthe r reduce NOx emissions. The PWV for LoTOx applications at Refineries 5 and 6 were estimated based on the PWV for LoTOx applications at Refineries 4 and 7 and the ratios of their appropriate inlet flue gas flow rates to the 0.7 power as follows:

PWV Ref 5 = PWV Ref 5 x (Flow Rate Ref 5 / Flow Rate Ref 4 ) ^0.7 PWV Ref 6 = PWV Ref 7 x (Flow Rate Ref 6 / Flow Rate Ref 7 ) ^0.7
The present worth values and cost effectiveness values are summarized in Table A.7. The average cost effectiveness is $15 K per ton using DCF method and $25 K per ton using LCF method.
The manufacturer estimated that a plot space needed for the ozone generator and accessories to be about 25 ft x 35 ft. The first LoTOx applicati on was put in service in 1997. At that time, required a large foot print (e.g. 1 st generation LoTOx application at a Texa s refinery required a foot print of 30 ft x 80 ft.) The newer generation LoTOx app lication has a much smaller footprint (e.g. an equivalent unit to the Texas refi nery application now requires only 25 ft x 30 ft).

Table A. 7 - Costs and Cost Effectivene ss for LoTOx Applications (December 2014)

Fac Emissions NOx % Emission PWV CE ID (tpd) (ppmv) Control Reduction (tpd) ($M) ($/ton) 4 0.22 21-23 91% 0.20 19 10,767 [JW1] 7 0.14 13 84% 0.12 16 15,199 9 0.34 34-52 95% 0.32 32 10,631 5 0.16 15 87% 0.14 24 18,590 6 0.20 6 64% 0.13 34 29,502 Total for Ref 4,9,5,6 and 7 0.91 125 Avg <15,124

Staff did not include the costs for scrubbers and waste water treatment in Table A.7. Since Refinery 5 and 6 already have SCRs, they will likely to use their SCRs to control NOx. Staff included the costs for scrubbers with waste treat ment for Refineries 4, 7 and 9. Staff also estimated the overall cost effectiveness for th e LoTOx/scrubbing multi-component air pollution control as shown in Table A.8.

### 71 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table A. 8 – Revised Costs and Cost Eff ectiveness for LoTOx S crubbers (March 2015)

Fac NOx Emission SOx Emissi on PWV for PWV for Total CE ID Reductions Reductions LoTOx S crubbers PWV (K$/ton) (tpd) (tpd) ($M) ($M) ($M) 4 0.20 0.20 19 91 110 30 7 0.12 0.87 16 51 67 7 9 0.32 0.58 32 90 121 15 Note: 1) SOx emission reductions were taken from Table 3-11, Chapter 3, SOx RECLAIM Staff Report, dated November 2, 2010. 40 2) PWVs for scrubbers including waste treatment were based on information provided on Table 3-12, Chapter 3, SOx RECLAIM Staff Report, dated November 2, 2010, and a Marshall Swift Index of 1.1. 40 3) It is assumed that retrofitting existing scrubber for Refinery 7 would cost about half of the costs estimated for the installation of the new scrubber under SOx RECLAIM project.


## Incremental Costs and Cost Effectiveness

The BARCT level for the FCCUs in 2005 was set at 85% reduction. The costs for SCRs to meet 85% reductions were estimated to be $111.1 million. The emission reductions were estimated to be 0.48 tons per day. A Marshall index of 1.2 5 was used to raise the costs of $111.1 million dollars to current dollars of $138.88 million.
Table A.9 presents the Staff estimated the overall PWVs for 2 cases:

Case 1: Assume all 5 refineri es will use SCRs to achieve the proposed BARCT level of 2 ppmv. Using the low end costs for SCRs in Table A-5, the total PWVs to achieve 2 ppmv NOx level would be $152 million.

Case 2: Assume Refineries 5 and 6 will use SCRs (using the high end costs for SCRs in Table A.5) and Refineries 4, 7 and 9 will us e LoTOx and scrubbers (Table A-8) for multicomponent control. The total PWVs would be $375 million.

### 72 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table A. 9 – Present Worth Values of SCRs and LoTOx/Scrubbers for FCCUs (March 2015)
Fac ID Case 1 - PWV ($M) Case 2 - PWV ($M) 5 <33 (SCR) <36 (SCR) 6 <57 (SCR) <57 (SCR) 7 27 (SCR) 67 (LoTOx and Scrubber) 4 16 (SCR) 110 (LoTOx and Scrubber) 9 19 (SCR) 121 (LoTOx and Scrubber) Total 152 (all SCRs) 391 (SCRs and LoTOx/Scrubbers)

Incremental cost effectiveness to achieve a more stringent of 2 ppmv NOx from a less stringent level of 85% control during 25-ye ars life of the control device is listed in Table A.10. CE is estimated as follows:

CE incremental = (PWV 2 ppmv – PWV 85% control ) / ((ER 2 ppmv – ER 85% control ) x 25 yrs x 365 days)

Where: CE incremental = Incremental Cost Effectiveness, $/ton PWV 2 ppmv = Sum of all SCR (or LoTOx) costs to meet 2 ppmv, $ PWV 85% control = Sum of all SCR costs to meet 85% reduction, $ = $139 M ER 2 ppmv = Total emission reductions achieved at 2 ppmv NOx, tpd = 0.91 tpd estimated from 2011 baseline ER 85% control = Total emission reductions achie ved with 85% control, tpd = 1.08 tpd – 0.60 tpd = 0.48 tpd

Table A. 10 – Incremental Cost Effectiveness of SCRs and LoTOx Scrubbers for FCCUs (March 2015)
Emission Reductions (tpd) PWV ($M) SCR for 85% control 0.48 tpd NOx 139 SCR for 2 ppmv for all 5 Refineries 0.91 tpd NOx 152 SCR for 2 ppmv for Ref 5, 6 and 0.91 tpd NOx and 1.65 tpd SOx 391 LoTOx/Scrubber for Ref 4,7, 9 Case 1 – Incremental Emission Re ductions = 0.91 – 0.48 = 0.43 tpd NOx Incremental Cost Effectiveness: SCR – SCR for all 5 Refineries (152 - 139) / (0.91 – 0.48) / 25 / 365 = 3,444 $/ton DCF and 5,683 $/ton LCF Case 2 – Incremental Cost Effectiveness: SCR – S CR for Ref 5, 6, and SCR - LoTOx for Ref 4, 7, 9

(391 – 139) / (0.91 + 1.65 – 0.48) / 25 / 365 = 13K $/ton DCF and 23K $/ton LCF

### 73 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Staff’s Recommendation
Staff proposes a BARCT level of 2 ppmv NOx for FCCUs because 1) Refinery 1 FCCU’s SCR has achieved-in-practice 2 ppmv NOx at 5 ppmv NH3 slip; and 2) NOx control technologies such as SCR, LoTOx, and NOx reduction additives are commercially available and can be used in conjunction to achieve 2 ppmv NOx in a cost-effective manner. The cost information submitted by SCR and Lo TOx manufacturers support that a BARCT level of 2 ppmv NOx is feasible and cost-effective for FCCUs in the SCAQMD. It should also be noted that NOx reducing additives, which can reduce 50% or more of NOx emissions, can be used in parallel with SCRs and LoTO x applications if needed.
In summary:

Case 1: Total PWVs: $152 M with SCRs for all 5 refineries Total incremental costs: $13 M Incremental emission reductions: 0.43 tpd NOx Incremental cost effectiveness with SCRs: 3,444 $/ton DCF or 5,700 $/ton LCF

Case 2: Total PWVs: $391 M with SCRs for Refine ries 5 and 6 and LoTOx/scrubbers for Refineries 4, 7 and 9 Total incremental costs: $252 M Incremental emission reductions: 0.43 tpd NOx and 1.65 tpd SOx for 5 FCCUs Incremental cost effectiveness: 13K$/ton DCF or 23K $/ton LCF

### 74 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## References for FCCUs
1. Information on Refinery 1’s FCCU’s SCR. Email from Refinery 1 to Minh Pham, dated October 23, 2013. 2. Air Pollution Technology Institute (APTI) Course 415 – Control of Gaseous Emissions, Student Manual, Chapter 7 – Control of Nitrogen Oxide Emissions, December 1981. 3. Source Book on NOx Control Technology , U.S. EPA, EPA-600/2-91-029, July 1991. 4. EPA Air Pollution Cost Manual, Section 4 – NOx Controls, EPA/452/B-02-001, Sixth Edition, January 2002. 5. Reducing NOx and NH3 Emissions with Advanced SCR Technology. Rita Aiello, Kevin Doura, Mike Baran, Wilson Chu, PaulAnderson, Johnson Matthey. Paper #33233. A&WMA’s 107 th Annual Conference & Exhibition, June24-27, 2014, Long Beach California. 6. UltraCat Catalytic Filters Remove PM, SO 2 , HCl, NOx, Dioxins and HAPs. NOx Control as Low as 350 o F – TriMer’s brochure – www.tri-mer.com

. 7. Combating NOx from Refinery Sources Using S CR. Haldor Topsoe. Presentation at the 2 nd Annual World Refining Technology Summit & Exhibition, 2010, Abu Dhabi. www.topsoe.com , posted online and downloaded in January 2014. 8. Information posted online at the we bsite for Mitsubishi and Cormetech, www.cormetech.com/non-reductionh.htm , and www.mhpowersystems.com/scr.html , downloaded on January 2014. 9. SCR and Zero-Slip TM Technology. T.W. Has tings of Cormetech, Inc. and A. Hattori of Mitsubishi Power Systems, Inc. Presentati on of June 17, 2003 Turbo Expo – Atlanta, GA. 10. Dual Function Catalyst Promises High NOx Removal with Zero Ammonia Slip for Gas Turbine Applications. J.A. Rosin and H.S. Rosenberg. Power Engineering, September 2001, Vol. 105, Issue 9, page 76. 11. Optimization of Ammonia Source for SCR Applications. R. Salib and R. Keeth of Washington Group International. Paper Po ster Session No. 46. (no date) 12. Comparison of Urea Based Ammonia to Liquid Ammonia Systems for NOx Reduction Applications. J. E. Fisher, WAHLCO, Inc. 13. Comparison of Urea, 19% Aqueous Ammonia, a nd Anhydrous Ammonia Operating Costs. of Canyon Energy Project. D. Kirk of Fuel Tech Inc. to C. McFarlin of California Energy Commission, September 3, 2008.

### 75 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

14. Influence Factors and Control Research on Amm onium Bisulfate Formation in the Process of Selective Catalytic Redu ction. S. Ma et.al., North China Electric Power University. Journal of the Air & Waste Manuscript Paper UAWM-2013. 15. SCR Costs Information from Manufacturer A. E-mail to Minh Pham on December 26, 2013.
16. SCR Costs Information from Manufacture B. E-mail to Minh Pham on November 10, 2013.
17. SCR Costs Information from Manufacturer C. E-mail to Minh Pham on January 7, 2014. 18. Low Temperature Selective Catalytic Reduction of NOx with NH3 Using Perovskite Type Oxide Catalysts. Lishia Lai and Hsunling Baui of National Chiao Tung University and Shawyi Yan and Jungnan Hsu of Industrial Technology Research In stitute, Taiwan. Paper #32657. A&WMA’s 107 th Annual Conference & Exhibition, June24-27, 2014, Long Beach California.
19. LoTOx TM – Novel NOx Control Solution. Naresh J Suchak, Ph.D., Monica Caldwell, Peter Studer, Frank R Fitch, Ph.D., Li nde Gases. Paper #33612. A&WMA’s 107 th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 20. Meeting Tighter NOx Emission Rules – A Lo w Temperature Oxidation Technology Uses Ozone to Remove Very Low Leve ls of Nitrogen Oxide from Refi nery Gases. S. Harrison, N. Suchak, F. Fitch, Linde Gases. www.digitalrefining.com/article/1000954 . PTQ Q3 2014 21. Wet Scrubbing-based NOx Control Using Lo TOx Technology – First Commercial FCC StartUp Experience. Nicholas Confuorto of BE LCO Technologies, Jeffrey Sexton of Marathon Petroleum Company LLC. www.digital refi ning.com/article/1000812. September 2007 22. Preparing Wet Scrubbing Systems for a Future with NOx Emission Requirements. S. Eagleson and N. Confuorto, BELCO Technologies Corporation, www.digitalrefining.com/article/100833 . September 2013. 23. Low Temperature Oxidation System. California Air Resources Board Grant Number ICAT 99-1. www.arb.ca.gov/research/icat/projects/boc.htm#

. 24. Pilot-Scale Studies on NOx Removal from Flue Gas Via NO Oxidation and Absorption into NaOH Solution. M. Jakubiak, W. Kordylewski. Wroclaw University of Technology, Faculty of Mechanical and Power Engineering, Institute of Power Engineering and Fluid Mechanics, Poland.
25. Acid Gas Scrubber for Multi-Pollutant Reduction. Nicholas Confuorto, BELCO. Institute of Clean Air Companies (ICAC) - Emission Control and Measurement Workshop, March 24-25, 2010. 26. LoTOx NOx Reduction Technology Installation List. Dupont BELCO Clean Air Technologies, dated May 2013.

### 76 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 27. Costs for LoTOx Applications to Meet 2 ppmv NOx for 3 FCCUs and Coke Calciner in the SCAQMD. Email of information provided by LoTOx manufacturer to Minh Pham, dated December 12, 2013 and January 20, 2014.
28. Best Practices for In-Situ SOx and NOx Emissi on Control in FCC Units. Todd Hochheiser, Bart de Graaf, Paul Anderson. Johnson Matthey. Paper #33231. A&WMA’s 107 th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 29. HCN and NOx Control Technologies in the FCC – Results of Research into Emissions from the FCC, plus Guidance on How to Obtain the Minimum Level of NOx Emissions from Full Burn FCC. Xunhoa Mo, Bart de Graaf, Ch arles Radcliffe, and Paul Diddams, Johnson Matthey, Process Technologies, Intercat/JM Additives. 30. FCC DeSOx and DeNOx Additive Technology.Wwn Bin, He Min-Yuan. Research Institute of Petroleum Processing, Beijing China. Journal of Environmental Scineces. Vol. 12, No. 3, pp.310 – 318, 2000.
31. FCC Flue Gas Scrubber Alternatives : Part I. Intercat/Johnson Matthey. 2009. www.digitalrefining.com

. 32. Reducing FCC Unit NOx Emissions . Intercat/Johnson Matthey. www.digitalrefining.com

. 33. Controlling FCC NOx Emissions. Grace Technol ogy Conference in Munich. September 2011. www.refiningoperations.com

. 34. FCC Catalysts and Additives for Costs and Emission Control. Grace Technologies. www.digitalrefining.com

. 35. Reduce FCC Regenerator SOx and NOx Emissions. RefineryOperations.com, Vol: 2, Iss: 7, April 20, 2011.
36. Products and Performance Data of BASF CLEANOx. www.basf.com

. 37. CLEANOx FCC NOx Reduction Additives. BASF. www.catalysts.basf.com/refining and information provided to Minh Pham on February 7, 2014

. 38. Costs Analysis for NOx Reduction Additives. Information from a manufacturer of NOx Reduction Additives to Minh Pham. February 21, 2014. 39. BARCT Analysis for SCAQMD NOx RECL AIM, Non-Confidential Report, Norton Engineering, November 26, 2014 (See Addendum 1) 40. SCAQMD’s Final Staff Report for SOx RECLAIM – Part I - BARCT Assessment & RTC Reductions Analysis, November 2, 2010.

### 77 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix B – Refinery Boilers and Process Heaters
Process Description
Boilers and process heaters are used extensively in almost all of the processes in refinery such as distillation, hydrotreating, fluid catalytic crackin g, alkylation, reforming, and delayed coking. Figure B.1 provides a simplified diagram of the processes where boilers and heaters are used. There are 23 boilers and 189 heaters in the refineri es classified as majo r or large NOx sources. The refinery heaters and boilers primarily burn re finery gas which is generated at the refinery. Most of these boilers and heaters use natural gas as back-up or supplemental fuel. Liquid fuel or solid fuel is rarely used in refinery boilers and heaters. The combustion of fuel generates NOx, primarily “thermal” NOx with small contri bution from “fuel” NOx and “prompt” NOx.

Crude Unit Mid-Distillate Hydrotreating Catalytic Reforming

Hydrocracking

FCCU Naphtha Hydrotreating Isomerization

Vacuum Distillation Delayed Coker Unit Alkylation T r e a t i
n g
B l e n d i
n g Crude LPG

Gasoline Organic Solvents

Aviation Fuels Diesels Lube Oils Heating Oils Refinery Fuel Oil Asphalts

Petroleum Coke Gasoline

Gasoline

As p halts Jet, Diesel Gasoline

Jet, Diesel

Gasoline Refinery Gas LPG

Figure B. 1 - Refinery Processes

### 78 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Emission Inventory

There are a total of 212 boilers and heaters clas sified as major and large NOx sources at the refineries. The distribution of boilers and h eaters and their emissions are shown in Table 5.1. Collectively, the 212 boilers and heaters emitte d about 7.39 tons per day in 2011. Their NOx concentrations at the stack vary from 1.6 ppmv for units equipped with selective catalytic reduction (SCR) to 120 ppmv for units with no control.

The 2005 RECLAIM amendments set BARCT leve ls between 5 ppmv to 12 ppmv for various categories of boilers and heaters. A comprehensive list of equipment specific NOx emission limits is provided in Table 3 of the SCAQMD Rule 2002 , amended January 7, 2005. As a component of the BARCT assessment, the decision was made to retain the 2000 BARCT level for boilers/heaters with maximum input rating betw een 40-100 mmBtu/hr at 25 ppmv. In 2005, it was estimated that 51 boilers/heaters would require SCRs to be instal led to reduce NOx emissions. Only 4 pieces of equipment were retrofitted with S CRs; these were in response to e ither an EPA consent decree or an order of abatement. If all of the boile rs and heaters had complied with the 2005 BARCT emissions from boilers and heaters would be redu ced from 7.39 tons per day to 1.92 tons per day, approximately 74% reduc tion in emissions.


## Achieved-In-Practice NOx Levels for Boilers and Heaters
The following is a summary of refinery boilers and heaters that have very low emission levels:

x Fourteen process heaters using refinery fu el gas in the SCAQMD ranging from 22 to 653 mmBtu/hr equipped with SCRs have achieved 1.6 - 3.5 ppmv NOx at 3% O 2 ;

x Two boilers, 400 HP and 1000 HP, using natural gas, equipped with Lo TOx scrubbers have achieved 2 - 5 ppmv NOx at 3% O 2 ;

x A crude heater using refinery fuel gas rating at 10 mmBtu/hr in Coffeyville refinery Kansas has been operated at 3 - 8 ppmv NOx at 3% O 2 with Great Southern Flameless technology without the use of SCR. All of the control technologies mentioned above are commercially available and can be designed to reach 2 ppmv NOx at 3% O 2 . 

## Control Technology
Commercially available c ontrol technologies are SCRs, Great Southern Flameless Heaters, and LoTOx applications with scrubbers. Other potential technolog ies on the horizon are ClearSign,

### 79 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Cheng Low NOx and KnowNOx. SCR, Great Southern Flameless burners and ClearSign burner technologies are discussed below. Cheng Low NOx, LoTOx and KnowNOx technologies are discussed in other Appendices. Other common c ontrol technologies such as Low NOx burners, Ultra Low NOx burners, or Selec tive Non Catalytic Reduction (SNCR) are not discussed here.
Selective Catalytic Reduction

SCR is an effective control technol ogy for NOx which uses ammonia (NH 3 ) to selectively reduce NOx to nitrogen through the following reactions.

Great Southern Flameless Heaters In 2012, Coffeyville Resources purchased the world’ s first flameless crude heater designed by Great Southern Flameless for their Coffeyville refinery in Kansas to comply with a Consent Decree issued by the U.S. EPA. The flameless heater has been in operation for over one year and has achieved-in-practice 5 ppmv NOx at 3% O2 wi th pilots in operation, and 3 ppmv NOx without pilots for flameless technology. Great S outhern Flameless confirmed the following: 18-21

x Flameless heaters can be designed to achieve:

 5 ppmv NOx at 3% O 2 ; or

 2 ppmv NOx at 3% O 2 with pilots off during flameless firing and with a fuel mix of 25% natural gas and 75% refinery gas.

x Oxy-fuel flameless heaters can be designed to achieve:

 2 ppmv NOx at 3% O 2 ; or

 1 ppmv with pilots off during flameless firing

Great Southern Flameless can s upply flameless heaters or oxy -fuel flameless heaters with maximum rating from 10 mmBtu/hr to 320 mmBtu/hr (240 mmBtu/hr process duty.) Their production capacity is 30 heaters per year. The modul es are designed and fabricated in Oklahoma, shipped in pieces to be field, and assembled at the site. The heaters can use the same foundation of the conventional heaters. Th e flameless heater desi gned by Great Southe rn Flameless for the Coffeyville refinery has the following characteristic:

x The heater is a polygon with the process coil (heat exchanger tubes) in the center and two “Flameless Nozzle Grouping” (FNG) located on the wall which fire tangentially. Each FNG consists of 2 conventional nozzles, 2 flameless fu el nozzles, 4 air nozzles and 1 nozzle for pilot fuel.

### 80 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

x To pin the flue gas in circulation against th e wall, Great Southern Flameless developed and patented a proprietary design for the heater’s interior wall. The interior wall of the heater has a dimple pattern in the refractory which holds the flue gas to the wall and allows the flue gas to circulate in high volume and velocity around th e heater until it eventually rotates out to the center of the heater, and up through the uptake ducts and into the conve ction section of the heater. This unique wall design eliminates hot gas impingement on the process coil located in the center of the heater and assures even heat radiation from the heater walls to the heat exchanger tubes.

x Great Southern Flameless also developed and has a patent pe nding for an automated 3-way switching valve. This valve allows the heater to be operated in three different firing modes:

 Conventional firing mode when all fuel gas is diverted to the 2 conventional nozzles;

 Staged firing mode when half of the fuel gas goes to the 2 conventional nozzles and the other half goes to the 2 flameless nozzles; and

 Flameless firing mode when all fuel gas goes to the 2 flameless nozzles and the combustion is sustained by the high temper atures of the combustion air.

x The heater has a balanced draft air-preheat system which generates high temperature combustion air. High temperature combustion ai r is required for the staged firing mode and the flameless firing mode to maintain the high auto-ignition temperature required for combustion. From cold start, the heater is brought up in natural draft mode in the same manner as any typical conventional heater. The firing rate of the heater is gradually increased to the required level while the combustion air is gradually increased to 850 degrees F. Once the combustion air temperature exceeds 850 degrees F, it will sustain the automatic ignition of fuel, and the heater is transitioned into the staged fuel firing mode with pilots off-line. The heater is operated in the staged firing mode until steady state operation is achieved. At this point, the heater is transitioned into flameless firing mode. Visible flame from the convent ional nozzles disappears and NOx emissions decreases significantly in the flameless mode operation. Table B.1 below tabulates the temperature profile in side the heater under the three modes of firing. With more even temperature distribution, the flameless firing mode results in 4 ppmv NOx compared to 77 ppmv NOx under conventional firing and 49 ppmv under staged firing mode. The Coffeyville heater average NOx emissions are in th e levels of 3 – 8 ppmvd without the use of high temperature high energy SCR system. The heater can be designed for combustion with oxygen. Combustion with oxygen in place of air will eliminate “prompt” NOx and reduce CO 2 emissions. Figure B.2 shows a flameless heater modified for oxygen combustion. Table B.2 lists the predicted performance of an oxy-flameless

### 81 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

heater. Flameless and oxy-flameless heaters come in modul es and can be stacked up to 320 mmBtu/hr rating.

Table B. 1– Temperature Zones and NOx Emissions of Great Southern Flameless Heater
Conventional Staged Flameless Firing Firing Firing Combustion Air Temperature, degrees F 804 893 909 Average Radiant Upper Level Temp, degrees F 1544 1740 1714 Average Radiant Mid Level Temp, degrees F 2050 1826 1476 Average Radiant Lower Level Temp, degrees F 1488 1627 1669 Excess Oxygen, % 3.7 2.6 2.4 NOx, ppmv 77 49 4

Figure B. 2 - Oxy-Flameless Heater (Reference 17)

### 82 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table B. 2 – Predicted Performance of Great Southern Oxy-Flameless Heater

Traditional Heater Flameless Heater Oxy-Flameless Heater NOx, ppmv Excess Oxygen, %

NOx, lb/mmBtu 31 3 4-8 3 0.0106 0-1 3 0.0021 or below

ClearSign Technology
ClearSign Combustion Corporation in Seattle has developed two technologies applicable for boilers and heaters: DUPLEXTM technology and Electrodynamic Combustion Control (ECCTM). ClearSign expected that these technologies would generate low concentrations of NOx and CO without the need for flue gas recirculati on (FGR), SCR or high excess air operation. DUPLEXTM technology can be installed in new boilers or heaters, or retrofit in existing boilers and heaters. The DUPLEX technology compri ses a proprietary DUPLEX tile installed downstream of conventional burners. The hot combustion flame from the conventional burners impinges onto the DULEX tile, and the tile helps radiate heat evenly with high emissivity to the combustion products. DUPLEX operation also creates more mixing and shorter flames. Since the flame length is one parameter that limits the total heat release in a furnace, decreased flame length can allow for significantly higher process throughputs. DUPLEX tile is expected to have a 3- to 5-year life. A demonstration project with San Joaquin Air Pollution Contro l District and efforts of scaling up the technology to heater s of 5 - 50 million BTU/hr are underway. 20
The Electrodynamic Combustion Control (ECCTM) uses an electric field to effectively shape the flame, accelerate flame speed, and improve flame stability. The total electrical field power required to generate such effects is less than 0.1% of the firing rate. Bench test performance estimates for DUPLEX and ECC indicated that NOx and CO were less than 5 ppmv, when furnace temperatures were steady maintained between 1200 and 1800 o F. Beside the benefits of reducing air pollution, Cl earSign believes that th eir burners will provide substantial economic bene fits from more uniform heat dist ribution, improved process throughput, and potentially reduced maintenance costs. 22-23

### 83 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Costs and Cost Effectiveness for SCRs
Staff developed a cost curve that plots the PWV of the control devices as a function of boiler/heaters’ maximum rating utilizing the following sets of data:

x Refinery Survey Data

x Refinery Consultant’s Analysis

x Data provided by three SCR manufacturers, Great Southern Flameless and ClearSign.

The PWVs determined from the cost curve were used to estimate the costs and cost effectiveness for all 212 boilers/heaters at the refineries. The details follow.
Survey Data As a component of the RECLAIM BARCT evaluation, a survey was submitted to the refineries in 2013 requesting cost information for their boilers and heaters operated with SCRs. There are 14 heaters at the refineries that currently achieve between 1.6 ppmv and 3.5 ppmv NOx at 3% oxygen with the use of SCRs. Table B.3 lists several key characteristics of the heater/SCR combination including: the 2011 emissions, the NOx concentrati on measured at the stack, the heater maximum rating, and the year of SCR installation, the equipment costs (in the ye ar of installati on), installation costs (in the year of installation), and annual operating cost s reported by the refineries. 13 A Marshall Index was used to bring the reported costs to the present dollars. Several heaters share a control device. Where this occurs, staff apportioned the reported costs for SCRs into individual SCR costs for each heater based on their relative maximum input ratings. The PWV of individual heaters are estimated using Equation 1 and 2. PWV = (TIC + (15.62 x AC)) x Marshall Index (Equation 1)

Where: PWV = Present Worth Value, $ TIC = Total Installed Costs, $ AC = Annual Operating Costs, $. The catal yst replacement costs we re reported as a part of the annual operating costs

PWV Heater A = PWV * R Heater A / R All Heaters (Equation 2) Where: PWV Heater A = Present Worth Value of Heater A R Heater A = Maximum Rating of Heater A R All Heaters = Total Maximum Rating of All Heaters

### 84 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 From the set of all 14 data points above , staff obtained the following ratios: Installation Costs = 2.807 x Equipment Costs Total Installed Costs = 3.870 x Equipment Costs Present Worth Values = 4.072 x Equip Costs = 1.052 x Total Installed Costs (Equation 3).
Table B. 3 – Costs of SCRs Estimated Based on Information Submitted by Refinery

Device Process mmBtu/ 2011 Existing Shared PWV ($M) hr Emissions NOx ppmv Control (Tons) at 3% O2 Heater FCCU 51 13.5 59 Yes 2.56 Heater FCCU 39 8.24 59 Yes 1.96 Heater Crude 350 68.6 33 No 6.84 Heater Crude 154 15.82 20 No 6.02 Heater Cat Reform 116 10.32 33 Yes 3.89 Heater Cat Reform 68 7.31 33 Yes 2.83 Heater Cat Reform 71 5.12 33 No 2.38 Heater Cat Reform 56 6.09 33 Yes 1.88 Heater Cat Reform 19 0.8 33 Yes 0.64 Heater Cat Reform 110 48.64 75 Yes 3.7 Heater Cat Reform 100 16.17 75 Yes 3.36 Heater Cat Reform 70 25.73 75 Yes 2.35 Heater Cat Reform 42 21.16 75 Yes 1.41 Heater Cat Reform 24 13.1 75 Yes 0.81 Heater H2 Production 340 70.32 34 No 20.41 Boiler 11 Steam Generation 352 58.99 56 No 15.04 Boiler 8 Steam Generation 179 32.48 85 No 9.99 Boiler 6 Steam Generation 250 61.66 75 No 12.2 Refinery’s Consultant Study A refinery provided information to SCAQMD sta ff from a study conducted by their consultant. This study estimated actual costs to install SCRs for 18 heaters at the refinery. The heaters have capacity ranging from 39 - 352 mmBtu/hr. Several heaters were to share a common SCR. The estimated PWVs for these 18 heaters were calculated using the refinery consultant’s estimates for the total installed costs and a multiplier factor of 1.052 (Equation 3). The PWVs of common SCRs were apportioned as individual SCR costs for indi vidual heaters using the heater maximum ratings. The PWVs for 18 heaters are summarized in Table B.4. 1485Draft Final Staff Report – NOx RECLAIMOctober 6November December 4, 2015Table B. 4 – Performance and Cost Information of SCRs for Process Heaters from Refinery SurveyProcess mmBtu/hr 2011Emissions(Tons)Year ofInstallationExistingNOx ppmv(3% O2)SharedControlEquipmentCost($M)InstallationCost ($M)MarshallIndexPWV($M)Crude 85 0.42 2008 3.5 No 0.76 0.72 1.09 2.87Hydrotreating 28 1.29 2007 2.7 Yes 0.42 0.18 1.13 0.99Hydrotreating 22 0.55 2004 2.7 Yes 0.42 0.18 1.13 0.78Hydrotreating 13 0.42 2007 2.7 Yes 0.42 0.18 1.13 0.45Coking 176 17.06 1992 2.7 Yes 2.76 6.83 1.64 5.39Coking 176 17.15 1992 2.7 Yes 2.76 6.83 1.64 5.39Coking 176 20.79 1992 2.7 Yes 2.76 6.83 1.64 5.39Cat Reform 177 1.08 1994 1.6 Yes 1.95 5.85 1.56 3.88Cat Reform 125 0.89 1994 1.6 Yes 1.95 5.85 1.56 2.74Cat Reform 88 0.53 1994 1.6 Yes 1.95 5.85 1.56 1.93Cat Reform 199 1.43 1994 1.6 Yes 1.95 5.85 1.56 4.36H2 Production 653 8.93 2000 2.7 No 7.65 22.95 1.42 44.12Crude 83 0.86 2001 2.7 No 7.5 22.5 1.42 43.27Hydrotreating 78 0.27 2003 2.3 No 4.98 14.93 1.38 28.11Note: Staff used all 14 data points to estimate the ratios of 2.807, 3.870 and 4.072 in Equation 3 however staff did not include data point #13 and #14 on FigureB.3 since the costs of these data points are out of the norm (e.g. data point #13 of $43 million for a 83 mmBtu/hr heaters as compared to data point #12 of $44million for 653 mmBtu/hr heater.)

### 86 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

SCR Manufacturers All SCR manufacturers that staff contacted confirmed the following:

x It is feasible to achieve 2 ppmv NOx at 5 ppmv ammonia slip; and

x The costs for SCRs to achieve 2 ppmv NOx is about 10% higher than the costs of SCRs to meet 5 ppmv NOx. Three SCR manufacturers provided SCR equipment costs. Staff useda multiplication factor of 4 to estimate the PWVs using Equation 3 and the actual reported costs from several refineries submitted in response to the SCAQMD survey. After refinery visits, a multiplication factor of 4 was used to estimate the TIC (not PWV) as recommended by several refineries to reflect the difficulty of installing SCR for retrofit applications. 15-17 In addition, the following costs were added to the TIC of the SCRs listed in Table B.5:

 Induced draft fans:

o $1.26 M for 100 mmBtu/hr heater,

o $1.69 M for 163 mmBtu/hr, and

o $2.67 M for 350 mmBtu/hr as estimated by NEC 24

 Ammonia tanks: $1.5 M per NEC recommendation 24

 CEMS: $100,000 based on data sub mitted to the SCAQMD in previous CEMS applications.
Great Southern Flameless
Great Southern Flameles s provided costs data based on the fo llowing assumptions, and the results are summarized in Table B.6 and Table B.7. 20-21

x 5 ppmv NOx outlet concentration for standard flameless heater

x 3 ppmv NOx outlet for standard flameless heat er with pilots off during flameless firing

x 2 ppmv NOx outlet for standard flameless heater with pilots off during flameless firing and fuel conditioning (25% natural gas and 75% fuel gas)

x 1 ppmv NOx outlet concentration for st andard oxy-fueled flameless heater

x The equipment costs include burner management system (BMS) control

x Oxygen costs is estimated at $70 per ton for 93% oxygen concentration

x There is no difference in costs between the 2 ppmv and 5 ppmv NOx flameless heaters

x The PWV was estimated based on 4% interest rate and 20-25 years life for heaters

x The PWV for standard flameless includes the savings due to increase in efficiency (83% to 91%) over the conventional heaters

x The PWV for standard oxy-fuel flameless is based on 20% (mass) injection of O2 and includes the savings due to operating efficiency increase (83% to 93.5%)

### 87 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table B. 5 - Costs of SCRs Estimated Base d on Information from SCR Manufacturers
Unit Rating NOx in NOx out Equip Cost PWV NH3 (mmBtu/hr) (ppmv) (ppmv) ($ M) ($ M) (lb/hr) A 163 80 2 0.13 0.52 – 3.81 (note 7) 10 163 80 2 0.10 0.4 – 3.99 (note 7) 10 (NH 3 Slip Cat) B 100 100 5 0.27 (note 1) 1.08 – 3.94 (note 7) 17 100 100 2 0.30 1.30 – 4.16 (note 7) 17.5 350 100 5 0.33 (note 2) 1.30 – 6.0 (note 7) 57 350 100 2 0.38 1.50 – 6.0(note 7) 59 C 100 100 5 0.20 (note 3) 0.80 – 4.0 (note 7) 5.8 100 100 2 0.22 0.88 – 4.0 (note 7) 6.0 350 100 5 0.65 (note 4) 0.26 – 4.53 (note 7) 17.5 350 100 2 0.70 0.28 – 4.55 (notes 5,7) 17.8 Note: 1) SCR replacement costs were estimated to be $10,000 - $15,000 every 3 – 5 years; 2) SCR replacement costs were estimated to be $20,000 - $25,000 every 3 – 5 years; 3) SCR replacement costs were estimated to be $23,000 - $24,000 every 6 to 7 years ; 4) SCR replacement costs were estimated to be $70,000 - $72,000 every 6 to 7 years; 5) Manufacturer C also estimated annual operating costs based on ammonia costs of about $800 per ton, and using this data, the PWV of the SCR for the 350 mmBtu/hr heater to meet 2 ppmv would be $2,218,040 million which is in the range of $2,800,000 estimated by using the multiplier factor of 4 and the equipment costs provided by the manufacturer. 6) Ammonia slip is 5 ppmv in all categories listed in Table B-6. 7) The high end of the range includes the costs of SCR, induced draft fan, ammonia tank, and new CEMS.

Table B. 6 – Costs for Great Southern Flameless Heaters
Fired Duty HHV Equipment Costs Installation Costs Total Installed Costs (mmBtu.hr) ($) ($) ($) 32 1,909,005 3,818,010 5,727,015 117 3,813,040 7,626,080 11,439,120 187 4,345,000 8,690,000 13,035,000 321 5,332,800 10,665,600 15,998,400 Table B. 7 - Costs for Great Southern Flameless Heaters with Fuel Savings
Fired Duty HHV PWV for Flameless Heater PWV for Oxy-Fuel Flameless (mmBtu/hr) 2 ppmv NOx ($ M) 1 ppmv NOx ($ M) 32 4.9 10 117 7.8 22 187 7.0 32 321 5.5 50

### 88 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
ClearSign ClearSign provided the estimates summarized in Table B.8 for DUPLEX burners to achieve 5 ppmv NOx and also 2 ppmv NOx. Note that th eir estimates did not yet include the economic benefits for more uniform heat distribution or improved process throughp ut and potential reduced maintenance costs. ClearSign indicated that their cost estimates were conservative and can be adjusted due to market demand. In addition, Clear Sign provided an analysis showing the revenue savings of about $36,000 per ton NOx reduced us ing DUPLEX burners compared to SCR to achieve the proposed BARCT levels. 23

Table B. 8 - Costs for DUPLEX Burners
Maximum Input PWV for 2 ppmv DUPLEX PWV for 5 ppmv DUPLEX Rating (mmBtu/hr) ($ M) ($ M) 12 0.442 0.102 24 0.884 0.204 48 1.767 0.408 96 3.535 0.815 150 5.523 1.274 200 7.292 1.682 400 14.728 3.397
Present Worth Values and Cost Effectiveness The aggregated control equipment cost data for the boilers and heaters was sorted into 5 categories based on maximum firing rate and a representative maximum PWV for the control equipment in the category was set. Two sets of costs per firi ng rate were develope d: one set for a 5 ppmv emissions rate and a second group for a 2 ppmv emissions limit.
For 5 ppmv SCR:
0IRUPP%WXKUERLOHUVDQGKHDWHUV $10 M for > 100 – 200 mmBtu/hr boilers and heaters $20 M for > 200 – 400 mmBtu/hr boilers and heaters $30 M for > 400 – 600 mmBtu/hr boilers and heaters $45 M for > 600 mmBtu/hr boilers and heaters

Per manufacturer’s recommendation, the repres entative PWV cost for each category was multiplied by a factor of 1.1 for the 2 ppmv limit. A cost curve was then constructed relating the PWV for the control devices as a function of boiler/heater maximum rating determined from the five sets of data shown above. Figure B.3 illustrates the linear cost curve and distribution of

### 89 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 control equipment by PWV/firing rate. PWVs were estimated for each boiler/heater (from the 212 pieces of equipment in the inve ntory) using the linear equation. For 2 ppmv SCR: 0IRUXQLWVZLWKPD[LPXPUDWLQJPP%WXKU $11 M for units with maximum rating > 100 – 200 mmBtu/hr $22 M for units with maximum rating > 200 – 400 mmBtu/hr $33 M for units with maximum rating > 400 – 600 mmBtu/hr 49.5 M for units with maximum rating > 600 mmBtu/hr

Figure B. 3 – Revised PWVs of Control Device s for Refinery Boilers/Heaters (March 2015)

### 90 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Incremental Cost Effectiveness was estimated as follows based on the Discounted Cash Flow (DCF) method. A multiplication factor of 1.65 was us ed to estimate the cost effectiveness using the Levelized Cash Flow (LCF) method:
CE = PWV / (ER x 365 days x 25 years)

Where:
CE = Incremental Cost Effectiveness, $/ton PWV = Present Worth Value, $ ER = Incremental Emission Reductions, tpd Units with cost effectiveness exceeding $50,000 pe r ton were excluded from estimating the total emission reductions and the average cost effectiv eness for the category of boilers and heaters. Staff estimated there would be 103 units that woul d be cost effective with total PWVs of $254.5 Million and an average cost effectiveness of $27 K per ton NOx reduced as of December 2014.
Consultant’s Analysis for SCRs NEC concurred that the 2 ppmv BARCT level is feasible for refinery boilers/heaters >40 mmBtu/hr. However, NEC recommended using SCRs with 4 layers of catalysts. NEC stated:

“ NEC feels that 2 ppmv NOx at 3% O 2 and 5 ppmv ammonia slip is an achievable BARCT level. If the refinery heaters and boil ers were only burning natural gas, this 2 ppmv NOx level could be achieved by instal ling three SCR cataly st beds in series. However, to improve the NOx removal efficiency while burning RFG, which is necessary as all of the heaters routinely operate in this mode, NEC recommends the addition of an Ammonia Slip Catalyst (AS C) bed downstream of the third SCR bed to enhance performance. The ASC bed will permit the SCR to operate with higher ammonia loadings when needed and still guarantee the 5 ppmv ammonia slip. An additional complication in controlling the NO x level on refinery heaters is that many of them have duties that change significantly over short periods of time due to process and feed variations. The ASC bed will also alleviate this difficulty.” 24
NEC estimated their cost profile based on data provided by a manufacturer for a FCCU’s SCR, upgrading the base cost for a 2-catalyst layer SCR to a 4-catalyst layer model. As with the FCCU example, the manufacturer’s co st proposal was adjusted by a 1.35 factor for bid conditioning followed by a 1.75 factor for labor and a 4.5 factor to estimate the total installed cost. The NEC 4-catalyst layer model added the costs of an i nduced draft fan, CEMS and an ammonia injection system to their prototype SCR. The resulting profile was sized for a series of heating rates to

### 91 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 establish cost curve that related PWV to mmBtu. Their cost equation was applied to the same boiler heater data set to estimate the cost eff ectiveness of achieving a 2 ppmv emissions rate. The difference between the staff and NEC cost estimates are greatest for the units less than 200 mmBtu/hr where the staff estimate is roughly ha lf of the NEC estimate (e.g., for 125 mmBtu/hr, staff: $11 million and NEC: $18 million). For h eating values approximately 300 mmBtu/hr and higher the costs estimate converge (e.g., fo r 525 mmBtu/hr, staff: $33 million and NEC: $32.7 million). The impact of applying the NEC algorithm resulted in higher costs for the units with lower firing rates and as a result only 48 heaters/boilers became cost-effective. A comparison between NEC and staff’s results are tabulated in Table B.9.

Table B. 9 - Comparison of NEC’s and Staff’ s Cost Estimates for SCRs (December 2014)

Total Boilers and Heaters Number of Cost-Effective Units Staff’s Estimates 212 103 Staff’s Estimates with NEC’s Cost Information 212 48 Total PWVs for Cost-Effective Units $254.5 M $162 M Total Emission Reductions Average Cost Effectiveness 1.05 tpd $27 K per ton DCF 0.61 tpd $29 K per ton DCF

It is important to acknowledge thatthe two approaches were similar in relating firing rate to PWV to estimate cost effective SCR applications. Howe ver the underlying the costs, including the sizing of the SCR catalyst layer configuration (1 to 4 layers) were distinctly different. Both assumptions yield estimates to achieve a 2 ppmv emissions target. The average cost effectiveness is essentially the same and less than the $30,800 thresholds established for SCR control equipment established for boilers greater than 75 mmBtu/hr in SCAQMD Rule 1146. The difference in total emissions reduced by the two methodologies is 0.44 TPD. Upon review of NEC’s analysis, staff agreed with the following recommendations from the refineries and revised its cost analysis accordingly: 1. The refineries requested staff to use a factor of 4 (not of 3, which was a combination of the 1.86 factor recommended in the EPA OAQPS Guidelines and 50% added contingency) to estimate the installed costs from the equipment costs provided by the manufacturers. Staff agreed with this recommendation and re vised the calculated PWVs based on the manufacturers’ information. Revised PWVs are included in Figure B.3 above.

### 92 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 2. For heaters <110 mmBtu/hr with existing SCRs, th e refineries requested staff to consider the full costs of SCR installations, not the “incremental” costs in estimating the cost effectiveness values. Staff concurred with this request.

Staff’s revised costs and cost effectiveness es timate are summarized in Table B.10. Table B.11 provides the details of the app lication of the revised methodology to the affected boilers and heaters. The revised analysis results in slightly lower incremental emission reductions and a nominal increase in cost. This revision modified the difference in total NOx emissions reduced by the staff and NEC methodologies to a new total of is 0.33 TPD. Note that an adjustment is proposed to reduce the overall NOx RECLAIM shave amount to account for uncertainties in the BARCT analysis related to these different me thodologies. The proposed adjustment is significantly larger than 0.33 TPD.

Table B. 10 – Revised Cost Estimate s of SCRs for Boilers and Heaters

Total Boilers and Heaters 212 No of Cost-Effective Units (<50,000 $/ton) 82 No of SCRs 75 (24 upgraded, 51 new) Total PWVs for Cost-Effective Units 237 Total Emission Reductions 0.94 ton per day Average Cost Effectiveness 28 K $/ton DCF, 45 K $/ton LCF



## Staff’s Recommendation
Staff proposes to set a new BARCT level of 2 ppmv NOx for refinery boilers/heaters >40 mmBtu/hr because NOx control technologies such as SCR, LoTOx, Great Southern Flameless heaters are either commercially available, achieved- in-practice and/or can be designed to achieve 2 ppmv NOx in a cost-effective manner. Incremental Emission Reductions bey ond 2005 BARCT level: 0.94 tons per day Total Incremental Costs: $ 237 M Average Incremental Cost Effectiveness: $28 K/ton (DCF) and $45 K/ton LCF)

### 93 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table B. 11 – Details of Cost Es timates for Boilers and Heaters 

### Summary of CE for Boilers/Heaters Results: Total units = 23 boilers + 189 heaters = 212 units Cost-effective units = 82. Not cost-effective units = 130 Total SCRs = 75 (24 upgraded, 51 new) Total PWVs = 237 millions. Total emission reductions = 0.94 tpd. Average cost effectiveness = 27,710 $/ton DCF = 45 K $/ton LCF

1
2
3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Fac ID Devic e ID Device Process Name Max Rating for Boilers Heaters (mmbtu/hr) 2011 Emissions

(tpd) Emission Reductions

Beyond 2005 BARCT (tpd) PWV for 2 ppmv SCR

= 1.1 * PWV of 5 ppmv SCR

($ M) PWV for 5 ppmv

SCR ($ M) Increment costs ($ M) Increment CE ($/ton) Existing Control and

Year Existing NOx at 3% O2

6 925 HEATER H2 PRODUCTION 931 0.06 0.03 49.50 45.00 4.50 19,066 SCR 87 5.65
5 3530 HEATER H2 PRODUCTION 653 0.02 0.02 49.50 45.00 4.50 30,425 SCR 00 2.69
1 570 HEATER H2 PRODUCTION 650 0.10 0.02 49.50 45.00 4.50 20,782 SCR 85, LNB 6 12.66 1 27 HEATER CRUDE 550 0.13 0.02 33.00 30.00 3.00 17,671 LNB 97 21.18 6 913 HEATER CRUDE 457 0.09 0.01 33.00 30.00 3.00 21,995 SCR 92 13.68 1 1465 HEATER H2 PRODUCTION 427 0.03 0.01 33.00 30.00 3.00 24,476 SCR, LNB 95 7.25 5 641 HEATER HYDROCRACKING 365 0.18 0.02 22.00 20.00 2.00 13,703 LNB 99 27.69 8 429 BOILER STEAM GEN/SCR09 352 0.03 0.01 22.00 20.00 2.00 25,992 SCR 2009 6.00 8 430 BOILER 11 STEAM GEN 352 0.16 0.01 22.00 20.00 2.00 27,891 8 59 HEATER CRUDE 350 0.19 0.01 22.00 20.00 2.00 16,363 7 220 HEATER H2 PRODUCTION 350 0.08 0.01 22.00 20.00 2.00 22,064 SCR 1990 21.66 5 2216 BOILER STEAM GEN 342 0.11 0.01 22.00 20.00 2.00 22,257 SCR 88 47.16 6 1236 BOILER STEAM GEN 340 0.01 0.01 22.00 20.00 2.00 23,944 SCR 97 6.76 8 210 HEATER H2 PRODUCTION 340 0.19 0.01 22.00 20.00 2.00 25,457 6 1239 BOILER STEAM GEN 340 0.02 0.01 22.00 20.00 2.00 27,239 SCR 97 7.75 5 82 HEATER CRUDE 315 0.02 0.01 22.00 20.00 2.00 18,018 SCR 91 5.69 5 83 HEATER CRUDE 315 0.02 0.01 22.00 20.00 2.00 19,885 SCR 91 5.69 1 535 HEATER CAT REFORM 310 0.07 0.01 22.00 20.00 2.00 27,440 LNB 94 22.84 6 803 BOILER STEAM GEN 309 0.21 0.01 22.00 20.00 2.00 41,496 LNB 86 104.00 7 686 BOILER 7 STEAM GEN 304 0.02 0.01 22.00 20.00 2.00 31,442 SCR 2009 8.50 1 63 HEATER CRUDE 300 0.01 0.01 22.00 20.00 2.00 24,097 SCR, LNB 94 4.81 6 805 BOILER STEAM GEN 291 0.19 0.01 22.00 20.00 2.00 42,085 LNB 88 74.91 1 532 HEATER CAT REFORM 255 0.04 0.01 22.00 20.00 2.00 34,138 LNB 01 16.64 7 688 BOILER 6 STEAM GEN 250 0.17 0.01 22.00 20.00 2.00 42,403 9 1550 BOILER/ne w SCR STEAM GEN 245 0.02 0.01 22.00 20.00 2.00 26,507 SCR 2008 5.39 5 643 HEATER HYDROCRACKING 220 0.04 0.01 22.00 20.00 2.00 31,409 LNB 99 19.63 5 84 HEATER CRUDE 219 0.02 0.01 22.00 20.00 2.00 23,986 SCR 91 5.69 5 20 HEATER CRUDE 217 0.06 0.01 22.00 20.00 2.00 31,482 LNB 01 23.16 9 430 HEATER HYDROTREATING 200 0.02 0.01 11.00 10.00 1.00 12,602 SCR 8.43 4 9 HEATER CRUDE 199 0.10 0.01 11.00 10.00 1.00 14,133 SCR 31.91 - 41.32 5 3031 HEATER CAT REFORM 199 0.00 0.01 0.00 0.00 0.00 0 SCR 94 1.64

### 94 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 1 2 3 4 5 6 7 8 9 10 11 12 Fac ID Device ID Device Process Name Max Rating for Boilers Heaters (mmbtu/hr) 2011 Emissions

(tpd) Emission Reductions

Beyond 2005 BARCT (tpd) PWV for 2 ppmv SCR = 1.1 * PWV of 5 ppmv SCR

($ M) PWV for 5 ppmv SCR

($ M) Increment costs ($ M) Increment CE ($/ton) Existing Control and

Year Existing NOx at 3% O2

7 687 BOILER 8 STEAM GEN 179 0.09 0.00 11.00 10.00 1.00 25,410 5 471 HEATER CAT REFORM 177 0.00 0.00 0.00 0.00 0.00 0 SCR 94 1.64 5 161 HEATER COKING 176 0.06 0.01 11.00 10.00 1.00 18,504 SCR 92 2.71 5 159 HEATER COKING 176 0.05 0.01 11.00 10.00 1.00 18,504 SCR 92 2.71 5 160 HEATER COKING 176 0.05 0.01 11.00 10.00 1.00 20,355 SCR 92 2.71 8 104 HEATER COKING 175 0.05 0.00 11.00 10.00 1.00 22,645 8 105 HEATER COKING 175 0.05 0.00 11.00 10.00 1.00 24,004 6 914 HEATER CRUDE 161 0.04 0.01 11.00 10.00 1.00 17,704 SCR 92 13.70 8 78 HEATER CRUDE 154 0.04 0.01 11.00 10.00 1.00 21,401 8 79 HEATER CRUDE 154 0.04 0.00 11.00 10.00 1.00 23,180 1 29 HEATER CRUDE 150 0.05 0.00 11.00 10.00 1.00 26,662 LNB 94 35.74 4 388 HEATER HYDROCRACKING 147 0.12 0.01 11.00 10.00 1.00 20,879 SCR 49.6 - 73.5 4 1122 BOILER H2 PRODUCTION 140 0.01 0.00 11.00 10.00 1.00 26,106 SCR 7.7 - 8.1 9 6 HEATER CRUDE 136 0.04 0.01 11.00 10.00 1.00 21,766 19.31 7 264 HEATER HYDROCRACKING 135 0.05 0.00 11.00 10.00 1.00 35,517 1 155 HEATER COKING 130 0.05 0.00 11.00 10.00 1.00 33,211 LNB 00 39.55 1 31 HEATER CRUDE 130 0.04 0.00 11.00 10.00 1.00 35,015 LEA 01 29.21 1 153 HEATER COKING 130 0.04 0.00 11.00 10.00 1.00 36,700 LNB 97 36.14 1 151 HEATER COKING 130 0.04 0.00 11.00 10.00 1.00 37,286 LNB 97 39.39 6 930 HEATER HYDROCRACKING 129 0.06 0.00 11.00 10.00 1.00 36,151 ULNB 95 55.12 9 378 BOILER STEAM GEN 128 0.01 0.01 11.00 10.00 1.00 20,725 SCR 5.17 6 120 HEATER COKING 126 0.05 0.00 11.00 10.00 1.00 38,824 LNB 95 51.79 5 472 HEATER CAT REFORM 125 0.00 0.00 0.00 0.00 0.00 0 SCR 94 1.64 1 67 HEATER CRUDE 120 0.04 0.01 11.00 10.00 1.00 20,294 LNB 94 34.37 4 90 HEATER FCCU 127 0.06 0.00 11.00 10.00 1.00 44,113 LNB 46.6 - 52.1 3 77 BOILER STEAM GEN 112 0.05 0.00 11.00 10.00 1.00 44,197 3 76 BOILER STEAM GEN 112 0.05 0.00 11.00 10.00 1.00 44,197 9 768 HEATER HYDROTREATING 110 0.02 0.04 11.00 31,494 SCR 9.43 7 154 HEATER CAT REFORM 110 0.13 0.03 11.00 41,628 5 451 HEATER HYDROTREATING 102 0.10 0.03 11.00 40,338 no control 99.31 1 33 HEATER CRUDE 100 0.02 0.02 5.50 25,116 LNB 94 22.79 7 155 HEATER CAT REFORM 100 0.04 0.01 5.50 47,328 9 22 HEATER COKING 95 0.02 0.02 5.50 29,430 20.33 4 89 HEATER FCCU 95 0.05 0.08 5.50 7,718 LNB 46.6 - 52.1 6 269 HEATER HYDROTREATING 94 0.03 0.01 5.50 44,210 LNB 88 34.10 6 918 HEATER COKING 91 0.08 0.02 5.50 34,411 LNB 91 91.70 6 917 HEATER COKING 91 0.07 0.02 5.50 38,067 LNB 98 82.07 1 250 HEATER FCCU 89 0.02 0.02 5.50 32,240 LNB 95 27.87 5 473 HEATER CAT REFORM 88 0.00 0.02 0.00 0 SCR 94 1.64

### 95 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

13 14 15 16
17 18 19 20 21 22 23 24 Fac ID Devic e ID Device Process Name Max Rating for Boilers Heaters (mmbtu/hr) 2011 Emissions

(tpd) Emission Reductions

Beyond 2005 BARCT (tpd) PWV for 2 ppmv SCR

= 1.1 * PWV of 5 ppmv SCR

($ M) PWV for 5 ppmv

SCR ($ M) Increment costs ($ M) Increment CE ($/ton) Existing Control and

Year Existing NOx at 3% O2

7 146 HEATER HYDROTREATING 76 0.02 0.01 5.50 43,097 6 85 HEATER COKING 74 0.06 0.01 5.50 45,265 LNB 88 97.00 8 174 HEATER HYDROTREATING 70 0.06 0.02 5.50 35,422 9 53 HEATER HYDROTREATING 68 0.01 0.02 5.50 32,565 16.43 6 84 HEATER COKING 67 0.04 0.01 5.50 44,780 LNB 85 116.81 6 83 HEATER COKING 67 0.05 0.01 5.50 45,124 LNB 88 103.95 4 770 HEATER HYDROTREATING 63 0.00 0.02 5.50 32,156 SCR 5.5 - 6.4 5 625 HEATER HYDROCRACKING 63 0.06 0.01 5.50 47,614 no control 90.40 7 194 HEATER HYDROTREATING 60 0.05 0.02 5.50 39,909 4 218 HEATER CAT REFORM 60 0.02 0.01 5.50 40,392 LNB 29.8 - 32.2 5 619 HEATER HYDROCRACKING 57 0.05 0.01 5.50 45,968 no control 95.47 5 617 HEATER HYDROCRACKING 57 0.05 0.01 5.50 40,839 no control 84.24 Summa ry tpd

>110 0.44 93.50 40-110 0.495 143.00 Total Units 0.94 Total costs 237 Average CE 27,710

### 96 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## References for Boilers and Heaters

1. Staff Report of Proposed Amendments to SOx RECLAIM. Agenda 37 of the SCAQMD Governing Board Meeting. November 5, 2010. 2. EPA Air Pollution Cost Manual, Section 4 – NOx Controls, EPA/452/B-02-001, Sixth Edition, January 2002. 3. Reducing NOx and NH3 Emissions with Advanced SCR Technology. Rita Aiello, Kevin Doura, Mike Baran, Wilson Chu, PaulAnderson, Johnson Matthey. Paper #33233. A&WMA’s 107 th Annual Conference & Exhibition, June24-27, 2014, Long Beach California. 4. UltraCat Catalytic Filters Remove PM, SO 2 , HCl, NOx, Dioxins and HAPs. NOx Control as Low as 350 degrees F – TriMer’s brochure – www.tri-mer.com

. 5. Combating NOx from Refinery Sources Using S CR. Haldor Topsoe. Presentation at the 2 nd Annual World Refining Technology Summit & Exhibition, 2010, Abu Dhabi. www.topsoe.com , posted online and downloaded in January 2014. 6. Information posted online at the we bsite for Mitsubishi and Cormetech, www.cormetech.com/non-reductionh.htm , and www.mhpowersystems.com/scr.html , downloaded on January 2014. 7. SCR and Zero-Slip TM Technology. T.W. Has tings of Cormetech, Inc. and A. Hattori of Mitsubishi Power Systems, Inc. Presentati on of June 17, 2003 Turbo Expo – Atlanta, GA. 8. Dual Function Catalyst Promises High NOx Removal with Zero Ammonia Slip for Gas Turbine Applications. J.A. Rosin and H.S. Rosenberg. Power Engineering, September 2001, Vol. 105, Issue 9, page 76. 9. Optimization of Ammonia Source for SCR Applications. R. Salib and R. Keeth of Washington Group International. Paper Po ster Session No. 46. (no date) 10. Comparison of Urea Based Ammonia to Liquid Ammonia Systems for NOx Reduction Applications. J. E. Fisher, WAHLCO, Inc. 11. Comparison of Urea, 19% Aqueous Ammonia, and Anhydrous Ammonia Operating Costs, Canyon Energy Project. D. Kirk of Fuel Tech Inc. to C. McFarlin of California Energy Commission, September 3, 2008.
12. Influence Factors and Control Research on Amm onium Bisulfate Formation in the Process of Selective Catalytic Redu ction. S. Ma et.al., North China Electric Power University. Journal of the Air & Waste Manuscript Paper UAWM-2013.

### 97 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
13. SCR Costs Data Provided to SCAQMD st aff – Refinery Survey. June 2013
14. SCR Costs Information from a Re finery Consultant’s Study. Refinery meeting with the SCAQMD staff. February 21, 2013. 15. SCR Costs Information from Manufacturer A. E-mail to Minh Pham on May 5, 2014.
16. SCR Costs Information from Manufacturer B. E-mails to Minh Pham on May 8 and May 14, 2014.
17. SCR Costs Information from Manufacturer C. E-mails to Minh Pham on May 8 and May 14, 2014.
18. The World’s First Flameless Crude Heater.William C. Gibson, Marianne Zimola. Paper #32895. A&WMA’s 107 th Annual Conference & Exhibiti on, June 24-27, 2014, Long Beach California. 19. Oxy-Flameless Combustion for Refinery Pro cess Heaters. William C. Gibson, Marianne Zimola. Paper #32899. A&WMA’s 107 th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California.
20. Information for Great Southern Flameless. E-mails from Bill Gibson and Marianne Zimola to Minh Pham. November 2013 and July 2014.21. Costs Information for Great Southern Flameless Heaters and Oxy-Fuel Flameless Heaters. Emails from Marianne Zimola to Minh Pham, July 18-30, 2014. 22. ClearSign Demonstrates Sub 5 ppmv NOx and CO without SCR, FGR, or High Excess Air. Joseph Colannino. Paper #33165. A&WMA’s 107 th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 23. Costs Information from ClearSign. E-mails from Roberto Ruiz to Minh Pham. July 24-29, 2014. 24. BARCT Analysis for SCAQMD NOx RECL AIM, Non-Confidential Report, Norton Engineering Consultants, N ovember 26, 2014. (See Addendum 1)

### 98 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix C – Refinery Gas Turbines
Process Description
Gas turbines are used in refineries to produce both electricity and steam. Frame gas turbines are exclusively used for power generation and con tinuous base load operation ranging up to 250 MW with simple-cycle efficiencies of approximately 40% and combined-cycle efficiencies of 60%. Aero-derivative gas turbines are adapted from aircraft engines. These turbines are lightweight and more efficient than frame turbines however the largest units are available for up to only 40-50 MW. The existing gas turbines at the refineri es in the SCAQMD range from 7 MW to 83 MW. Most are all operated with duct burners, heat recovery steam generator (HRSG), Selective Catalytic Reduction (SCR), CO catalysts and some units have Ammonia Slip Catalysts (ASC), Cheng Low NOx (CLN), and Dry Low NOx (DLN) or Dry Low Emissions (DLE) combustors. Figure C.1 shows a typical layout of a turbin e, duct burner, HRSG, and control system.

Figure C. 1 - Gas Turb ine with Duct Burn er (victoryenergy.com)

### 99 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Emission Inventory

There are a total of 21 gas turbines/duct burners classified as major NOx sources at the refineries in the SCAQMD. Collectively, the 21 gas turb ines/duct burners emitted about 1.33 tons per day in 2011 as shown in Table C.1. Table C.1 also includes information on the type and size of equipment, what controls are in place, and the year the controls were installed. NOx levels at the stack vary from 1.67 ppmv at 15% O2 for units with SCR and ASC to 5.95 ppmv for units with SCR and water injection. 1
It should be noted that at the inception of the RECLAIM program, the SCAQMD staff provided allocations for the gas turbines based on the 2000 BARCT level of 62.27 lbs/mmscft. If all gas turbines/duct burners were operated at the 2000 BARCT level of 62.27 lb/ mmscft, the emissions from these turbines would amount to about 4.86 tons per day. In addition, these units are subject to either BACT limits or permit conditions that limit the annual ma ss emissions at the time the permits were issued: Refinery 1’s gas turbines/duct burners have a BACT limit of 8 ppmv NOx; Refinery 5, 6 and 7’s units have a BACT limit of 9 ppmv; and units at Refinery 4 are subject to a limit of 583 tons per year of NOx emissions. If th ese gas turbines/duct burners were operated at the BACT levels or at the levels specified in the permit conditions at th e time the permits were issued, the emissions would be 5.99 tons per da y, higher than 4.86 tons per day of the 2000 BARCT. All of the gas turbines are currently e mitting at a level below their allocations and below the levels at the time their permits were issued. Technology improvement s with time and the implementation of BACT levels have recently changed emissions to 2 ppmv for frame turbines and 2.5 ppmv for aero-derivative units. 

## Achieved-In-Practice NOx Levels for Gas Turbines

x Refinery 10’s 7 MW aero-derivative gas turb ine/duct burner with Cormetech SCR and ASC operating under a permit conditi on of 2.5 ppmv NOx, 15% O 2 has actually achieved the levels 1, 6, 9, 25 below 2 ppmv NOx at 15% O 2.

x In 2010, Refinery 5 received a permit to cons truct a new 46 MW frame gas turbine/duct burner with DLN, SCR and CO catalysts. The permit has a limit of 2 ppmv NOx, 15% O 2 and 5 ppmv NH3 slip. This unit has been in operation since 2012. 28-29

x In 2011, Refinery 1 received a permit to constr uct for aan 85 MW gas turbine /duct burner with DLN, SCR and CO catalyst. The permit condition required the turbine to be operated at a BACT level of 2 ppmv NOx, 15% O2. Regardless of the permit, Refinery 1 did not install the gas turbine. 7

### 100 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
The above 7 MW aero-derivative, 46 MW a nd 85 MW frame gas turbines/duct burners demonstrate the feasibility of the proposed le vel of 2 ppmv NOx, 15% O2, annual average, for gas turbines using natural gas as well as refinery gas. The limits stated in the permit conditions are based on short-term averages (e.g. 1-hour aver age), which is more stringent than the proposed BARCT at 2 ppmv, annual average.

Table C. 1 - 2011 Emissions for Refi nery Gas Turbin es/Duct Burners

Fac ID Device ID Device mmBtu/hr MW Turbine Type 2011 Emissions (lbs) Control & Year Existing ppmv NOx at 15% O2 1 1226 Turbine 986 83 GE 78,418 DLE, SCR, CO, 88 2.80
1 1227 Duct Burner 340 27,097 SCR, CO, 88 2.80 1 1233 Turbine 986 83 GE 69,996 SCR, CO 98 3.50
1 1234 Duct Burner 340 22,034 SCR, CO 98 3.50 1 1236 Turbine 986 83 GE 72,933 SCR, CO, 88 2.53
1 1237 Duct Burner 340 21,090 SCR, CO, 88 2.53 1 1239 Turbine 986 83 GE 85,228 SCR, CO, 88 2.52
1 1240 Duct Burner 340 15,262 SCR, CO, 88 2.52 6 926 Turbine 316 23 GE 110,546 SCR, 87 5.65 4 810 Turbine 392 30 Pratt Whitney 55,264 SCR, CO, WI 5.95 4 812 Turbine 392 30 Pratt Whitney 50,084 SCR, CO, WI 4.82 7 828 Turbine 646 59 Westinghouse 118,842 SCR, 86 5.65
7 829 Duct Burner 99 16,191 SCR, 86 5.65 5 2198 Turbine A 560 46 GE Frame6 73,759 SCR, 95 4.20
5 2199 Duct Burner 120 7,521 SCR, 95 4.20 5 2207 Turbine B 560 46 GE Frame6 61,809 SCR, 95 3.46
5 2208 Duct Burner 120 9,569 SCR, 95 3.46 5 3053 Turbine C 506 46 GE Frame6 68,408 SCR, 96 4.24
5 3054 Duct Burner 286 5,686 SCR, 96 4.24 10 677 Turbine 90 7 Solar, Taurus 1,598 SCR, ASC, 03 1.67
10 679 Duct Burner 50 Solar, Taurus 430 SCR, ASC, 03 1.67 Total (tpd) 1.33

### 101 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Control Technology
Gas turbines/duct burners are capable of emitting very low NOx emission levels. Currently most of the units at the refineries in SCAQMD are emitting less than 5 ppmv NOx using commercially available control technologies such as water or steam injection, DLN, DLE, CLN, SCR, CO catalysts and ASC. Water or Steam Injection Most of the NOx generated in the gas turbine/ duct burner is “thermal” NOx. Water or steam injected into the high temperature frame zone quench the temperature down and reduce NOx to approximately 25 ppmv at 15% O2. However, water/steam injection tends to increase the CO emissions appreciably. Dry Low NOx (DLN) and Dry Low Emissions (DLE)
DLN/DLE is based on a concept of lean premixedcombustion – gaseous fuel is premixed with combustion air at the air to fuel ratio two times higher than the stoichiometric ratio. The lean mixture reduces peak flame temperature in th e combustion zone and suppresses “thermal” NOx formation. The premixing chamber for the combus tion air and gaseous fuel must be specifically designed for each type of turbines and integrated into the turbine design. Every 4 to 5 years, the combustion liners of the DLE/DLN combustors are de teriorated and must be replaced. Table C.2 shows potential performance of DLN/DLE in certai n models of GE frame and aero-derivative turbines. A few models of natural-gas-fired turbines can reach as low as 3-5 ppmv NOx. Maintaining the low NOx emission levels from the turbines from full to low load, or from turbines with varying load swings coupled with the emi ssions from the duct burners remain a challenge for DLN/DLE combustor technology. Most manufac turers would guarantee a level of 15-25 ppmv for DLE/DLN combustors. 14-16

Table C. 2 – Performance of DLN and DLE Combustion System Frame Type Potential NOx Level DLN1 GE 3/5/6B/7/9E 9-25 ppmv DLN1 GE 6B/7E/9E 3-5 ppmv DLN2.6 GE 6F/7F 9 ppmv DLN2.6 GE 9F 9 ppmv Combustion System Aero-derivative Type Potential NOx Level DLE GE LMS100 (100 MW) 25 ppmv (gaseous fuel) DLE GE LM6000 (40-55 MW) 15-25 ppmv (gaseous fuel) 100 ppmv (liquid fuel) DLE GE LM2500 (28 – 34MW) 15-25 ppmv (gaseous fuel) 100 ppmv (liquid fuel)

### 102 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Cheng Low NOx (CLN) Cheng Low NOx is an alternative to DLN/DLE. 17-23 In lieu of premixing air to fuel, CLN premixes steam with fuel prior to combus tion. The difference in the CLN a nd the traditional steam injection technology is that CLN can deliver a uniform homog enous mix of steam and fuel to the combustion chamber. A schematic diagram for th e CLN is shown in Figure C.2. The effect of homogeneity on CO and NOx emissions is shown in Figure C.3. With careful mixing, the steam to fuel ratio can be extended to 4 to 1 without causing any flameout and increasing CO emissions. The NOx level can theoretically be lo wered to 1 ppmv without the use of SCR. The CO level can be reduced to below 2 ppmv without the use of CO catalyst. 17-20 The CLN technology was developed by Cheng Powe r Systems, Inc. It was patented in 2002. Since 2005, the CLN technology has been running continuously on a 6 MW Allison Rolls Royce (RR) KB5S at the Stanford Research Institute (SRI) in Menlo Park. In2009, it was demonstrated on a GE LM2500 at Calpine Corporation’s Agnews Cogeneration Plant. The newest CLN was installed in the GE LM2500PH gas turbine. Tabl e C.3 below shows a list of CLN installations in the past decade.

Figure C. 2 - Cheng Low NOx (Reference 22)

### 103 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Figure C. 3 - Effect of Homogeneity and Steam to Fuel Ratio in CLN Application (Reference 22)

Table C. 3 – Installations of CLN
Engine Rated Power, MW RR 501 KH 6.2 RR 501 KB7S 5.2 RR 501 KB5 3.9 RR Avon 1535 15

GE LM2500 22 GE 6B 39.5 LM 6000 PC 43 GE 7EA 85

Figure C.4 below shows some of the test results of CLN. Additional test results can be found in References 18-20. It should be noted that, CLN was put in operation on two GE Frame 6B turbines at a refinery in the SCAQMD. Actual test data at the refinery site in the SCAQMD shows a level of 17.7 ppmv NOx at 15% O2 at the steam to fuel ratio of 1.5. 18-19 In addition to lowering NOx and CO emissions, additional benefits that CLN provide are lowering the heat rate and increasing power output.

### 104 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Figure C. 4 - Effect of Homogeneity and Ste am to Fuel Ratio on NOx Emissions in CLN Application In summary, CLN with a steam to fuel ratio of 1.7 5 to 1 is proven viable to reduce NOx emissions to 9 ppmv or 15 ppmv. SCR can be used in combination with CLN to reach 2 ppmv NOx and CO levels. The current CLN system comes with automatic adjustment so ftware to continuously monitor and optimize the amount of steam to fuel ratio. Cheng Power projects that with a steam to fuel ratio of 3 or 4 to 1, CLN would be able to reach 2 ppmv NOx without the use of SCR. 21-23 Selective Catalytic Reduction
SCR is an effective control technol ogy for NOx which uses ammonia (NH 3 ) to selectively reduce NOx to nitrogen. Please refer to Appendix A for further descriptions. All SCR manufacturers that staff contacted confirm that SCRs can be designed to reduce 95%- 98% NOx emissions when used in combination with DLE/DLN, CLN, CO catalysts, ASC, or water/steam injection. Two ppmv NOx can beachieved while maintain ing low ammonia slips of less than 5 ppmv. Cormetech indicated that they have ach ieved less than 2 ppmv NOx and 2 ppmv NH 3 in 10 gas turbines. In addition one of the full scale de monstration projects is a 7 MW cogeneration unit located at a refinery in the Los Angeles Basin (startup in 2003) that achieved <2 ppmv NOx at <0.1 ppmv ammonia slip. 25 BASF advertised that their vanadia/titania catalysts have 99% NOx

### 105 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 removal efficiency in the optimum temperature range of 550 – 800 degrees F, and their zeolite catalysts have 99% removal efficiency in the optimum temperature range of 675 - 1075 degrees F, and they also supply ASC that can reduce both ammonia and NOx. 27
The CO catalysts are used in conjunction with SCR catalysts to concurrently reduce NOx to nitrogen and oxidize CO and hydrocarbon to CO2 and water. The CO catalysts are typically made of platinum, palladium or rhodium, and have ab out 90% removal efficiency for CO and remove 85% to 90% of hydrocarbon or hazardous air pollutants. 

## Costs and Cost Effectiveness
It has been reported that the costs of SCR catal ysts have dropped signific antly over time – catalyst innovations have been the principle driver, resulti ng in a 20 percent reduction in catalyst volume and costs with no change in performance. 10 Staff developed a cost cu rve that plots the PWV of the control devices as a function of gas turbines ’ maximum rating utilizing the following sets of data:

 Refinery data

 EPA and DOE data

 Data provided by SCR manufac turers and Cheng Low NOx

Staff then used the PWVs from the cost curve to es timate the cost and cost effectiveness for all 21 turbines/duct burners at the refineries . The details are explained below.
Refinery 1’s Cost Information for SCR In 2011, Refinery 1 received a permit to construct for an 85 MW gas turbine/duct burner. It was planned as the fifth cogeneration unit at this site . SCR and CO catalysts were proposed to control NOx and CO emissions from a DLN combustor. Th e total installed costs for SCR and CO provided in their application for permit was estimated to be $5.9 million. Staf f used a Marshall Index factor of 1.2 to adjust to current dollars. 7
This refinery has four existing cogeneration units at the site emitting between 2.52 ppmv to 3.50 ppmv NOx. The refinery reported through a su rvey conducted in 2013 th at the annual operating costs were $375,000 per year, and catalyst repl acement costs were $950,000 every 10 years. 8
Using Equation 1 below with a Marshall Index adjus tment factor of 1.2 to bring the costs to present dollars, staff estimated the PWV for the SCR/ CO catalysts were approximately $15.50 million.

### 106 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 PWV = Adjustment Factor x (TIC + (15.62 x AC) + (1.14 x CR)) (Equation 1)

Where:
PWV = Present Worth Value, $ TIC = Total Installed Costs, $ AC = Annual Operating Costs, $ CR = Catalyst Replacement Costs, $
Refinery 10’s Cost Information for SCR This refinery has a 7 MW cogeneration unit thatis using SCR and ASC (installed in 2002) to achieve a level of 1.67 ppmv NOx at 15% O2. The refinery reported total installed costs, annual operating costs, and catalyst replacement costs every 10 years. Using Equation 1 with Marshall Index of 1.4, staff estimated the PWV for SCR/ASC catalysts of approximately $3.8 million. 6, 9

Costs Information from SCR Manufacturers All SCR manufacturers that staff contacted confirmed that it is feasible to achieve 2 ppmv NOx at 5 ppmv ammonia slip for natural gas as well as refinery gas applications using SCRs, or combinations of SCRs with CO, or ammonia slip catalysts. Manufacturer B provided the cost to add catalyst and increase the ammonia usage to the SCR of Refinery 1 to achieve 2 ppmv NOx. In this conservative estimate, Manufacturer B assumed that the existing NOx levels were at 10 ppmv. Manuf acturer B believed that with the current SCR system at Refinery 1, the refinery could m eet 2 ppmv NOx just by adding ammonia. 5 Additional catalysts = $234,000 ($250 per cubic foot) Additional ammonia = $11,000 based on $900 per ton ammonia
Manufacturer A provided several sets of cost info rmation for 1) conventional SCRs and for 2) an advanced SCR with ASC for 83 MW and 7 MW coge neration units with inlet NOx concentrations at 35 ppmv and 50 ppmv to get to 2 ppmv and 5 pp mv outlet NOx concentrations. The costs are summarized in Table C.4 below: 4

### 107 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table C. 4 – Costs of SCR and ASC fo r 83 MW and 7 MW Cogeneration Units
Engine Rated Power Rated Power Rated Power Rated Power 83 MW 83 MW 83 MW 7 MW Exhaust Flow, lb/hr 2,653,000 2,653,000 2,653,000 140,000

Exhaust Temp, o F 625 625 625 625 SCR + CO Catalysts NOx in, ppmv 35 50 35 50 NOx out, ppmv 2 2 8 (note) 2 CO Conversion, % 67 67 67 90

NH3 Slip, ppmv 5 5 5 5 Costs, $ 1,333,000 1,380,000 1,050,000 $75,000 SCR + Ammonia Slip Catalysts NOx in, ppmv 35 50 35 50 NOx out, ppmv 2 2 8 2 CO Conversion, % 92 92 67 92

NH3 Slip, ppmv 5 5 5 5 Costs $986,000 $1,100,000 $650,000 $60,000 Note: 8 ppmv NOx is the existing permit condition of Refinery 1’s cogeneration unit.

The SCR, CO and ASC have a catalyst replacem ent frequency of 10 years. Manufacturer B assumed that the existing ammonia storage tanks and injection systems can be used. Associated equipment such as pumps, control valves and vapo rizer capacity may increase costs however, this equipment was not included in the cost estimate. Installation and duct modifications were also not included in the cost estimate. Staff used a multiplie r factor of 1.6 to add the costs of modifications and installation based on Refinery 10 data. Assuming the entire existing SCR and CO catalysts were replaced with SCR and ASC using the costs provided by Manufacturer B, staff estimated the SCR/ASC’s PWVs would be approximately of $19 million for the 83 MW turbine and $2 million for the 7 MW turbine.

SCR Cost Information in Literature

Reference 2 contains extensive cost information for SCR catalysts to achieve 80% - 90% reduction from various inlet concen trations to 9 ppmv NOx outlet concen tration. The gas turbines in the SCAQMD currently have inlet NOx concentrations inthe range of 6 to 2.5 ppmv. An incremental reduction of 80% - 90% is needed to reach 2 ppm v NOx. Staff assumed that the entire SCR costs in Reference 2 can be used to estimate the “incremental” costs for the SCRs at the refineries to reach 2 ppmv. The estimated PWVs based on Reference 2 are $4.13 million for an SCR for a 7 MW turbine, and $22.44 million for an SCR for aan 83 MW turbine.

### 108 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Reference 3 contains the total installed costs and annual operati ng costs for conventional SCR to reach 79% NOx removal efficiency for a 4.2 MW , 23 MW and 161 MW turbines. Staff assumed that these costs can be used to reflect the “incremental” costs for the scenarios in the SCAQMD. Staff’s estimate of the incremental PWVs fo r SCRs would be $4 million for the 4.2 MW gas turbine, $11 million for the 23 MW gas turbines, and $41 million for the 161 MW gas turbines. Costs for Cheng Low NOx Cheng Power Systems provided the following info rmation on costs for CLN to meet 2 ppmv NOx. 20-21 In a presentation to the SCAQMD staff, Cheng compared the costs to operate a simple cycle 85 MW gas turbine with a Cheng cycle gas turbine to show that within a year of operation, the CLN would generate $9 million savings by reducing heat rate and increasing power, and that savings would offset the $5.5 million installation costs for the CLN. 21 The costs for Cheng Low NOx are listed in Tables C.5 and C.6.

Table C. 5 - Projected Income Gain Due to Power Increase for Cheng Low NOx
Engine RR 501 KB series Power (MW) 5.2 Percent Power Increase 20% RR Avon 1535

GE LM2500 15 22 20% 20% GE 6B LM 6000 PC 39.5 43 20% 16% GE 7EA 85 20% Note: For GE 6B, the increase in power during summer was from 34 MW to 42MW.

### 109 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table C. 6 - Equipment and Installation Costs for Cheng Low NOx for Various Types of Gas Turbines
Engine Power (MW) Hardware Installation/Software Total RR 501 KB series 5.2 $250,000 $125,000 $375,000

RR Avon 1535 15 $500,000 $350,000 $850,000

GE LM2500 22 $950,000 $650,000 $1,600,000 GE 6B 39.5 $1,700,000 $700,000 $2,400,000 LM 6000 PC 43 $1,800,000 $700,000 $2,500,000 GE 7EA 85 $3,000,000 $2,500,000 $5,500,000 Note: The above price assumes a CHP or Combined Cycle Plant with steam heat recovery system available. The extra costs of engine refurbishment or upgrade is to be determined based on a case by case basis and is not included in the above list.

Present Worth Values and Cost Effectiveness
Figure C.5 depicts a cost curve constructed relating the PWVs for the control devices as a function of turbine MW rating. The PWVs were then estimated for all gas turbines/duct burners to achieve 2 ppmv NOx with SCR/CO catalysts or SCR/ASC. See Table C.7. The PWVs with CLN/SCRs could be less if the savings resulting from increasing power would offset the CLN costs.

Figure C. 5 - Present Worth Values for Gas Turbines

### 110 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table C. 7 – Present Worth Values and Cost Effectiveness for Gas Turbines (December 2014)

No of Rating Current Incremental Emission Staff’s Estimate Incremental Cost Units (MW) NOx Reduction per Unit from PWV per Unit Effectiveness Level 2005 BARCT ($M) ($/ton) (ppmv) (tpd) 1 59 5.7 0.21 15.7 (new SCR) 8,210 3 46 3-4 0.31 12.6 (new SCR) 4,472 2 30 6 0.20 8.9 (new SCR) 4,851 1 23 5.7 0.14 7.2 (new SCR) 5,631 4 83 2.5-3.5 0.60 4.8 (add catalysts) 870

Total for all 10 units 4.14 97.68

Incremental cost effectiveness values were estim ated as follows based on the Discounted Cash Flow (DCF) method. A multiplication factor of 1.67 (to account for 25 years life of the SCR/CO/ASC system with frequency of catalyst re placement every 10 years) was used to convert the cost effectiveness estimated using DCF methodto the Levelized Cash Flow (LCF) method: CE = PWV / (ER x 365 days x 25 years)

Where: CE = Incremental Cost Effectiveness, $/ton PWV = Present Worth Value, $ ER = Incremental Emission Reductions, tpd
It should be noted that the cost estimates in Table C.7 above are conservative for several refineries as discussed below:

x Refinery 5’s gas turbines A, B, and C currently emit 3.5 - 4.5 ppmv NOx at 15% O 2 . Refinery 5 recently changed the catalysts used in Turb ine A and Turbine B from Hitachi to Cormetech, and reduced the catalyst’s volume from 2700 cubic feet to 667 cubic feet. The catalyst’s volume of Turbine C is 950 cubic feet. The ne w Turbine D at Refinery 5 uses only 300 cubic feet of Cormetech catalysts to reach 2 ppmv NO x. Turbine D has DLN. Turbines A, B have CLN with steam injection at steam to fuel ratio of 1.5. Turbine C has steam injection at a steam to fuel ratio of 1.3. It should be noted that the steam to fuel ratio for Turbines A and B was permitted at 2.1 – 2.6. Refinery 5 has several options to reach 2 ppmv NOx: 1) add additional catalysts or change to more effective catalysts, 2) increase the steam to fuel ratio, or 3) retrofit with CLN or DLN. Increasing the steam to fuel ratio could add more power to the system and return the investments within a couple years of operation. 20, 28-29

### 111 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

x Refinery 7 also changed the catalysts to Haldor Topsoe and Cormetech. With the use of more efficient SCR and ASC and additional ammonia, Refinery 7 may be able to reduce the catalyst volume and NOx emissions from 5 ppmv to 2 ppmv NOx without compromising the ammonia slip. 11, 25, 26, 31

x Refinery 4’s two 30 MW turbines currently use water injection, SCR and CO catalysts to achieve 5-6 ppmv NOx. The turbines have permit conditions limiting them to 96 ppmv NOx and 5 ppmv ammonia slip, and 583 tons per year NOx. Refinery 4 can retrofit the unit with steam injection or CLN technology, increase the power and reduce NOx without compromising the ammonia slip. Alternatively, the refinery may change to more effective SCR catalyst type and use ASC to reduce catalyst volume and in crease NOx reduction effectiveness without compromising the ammonia slip. 11, 20, 25, 26

x Refinery 10’s gas turbine/duct burner is alre ady at levels below 2 ppmv, thus no incremental costs were estimated for this refinery. In conclusion, staff proposes to set a new BARCT level of 2 ppmv NOx for refinery gas turbines, aero-derivative as well as frame turbines, becaus e NOx control technologies such as DLE/DLN, CLN, SCR with CO catalysts, SCR with ASC are commercially available and can be used together to achieve 2 ppmv NOx in a cost-effective manner. A level of 2 ppmv NOx is achieved-in-practice for an aero-derivative 7 MW gas turbine/duc t burner using SCR and ASC. Two 46MW and 83 MW frame cogeneration units with SCR and CO catalysts were give n permits to constructs since 2011 with permit conditions limiting to 2 ppmv NOx, 2 ppmv CO and 5 ppmv ammonia slip.

Consultant’s Estimates for SCRs
NEC agreed with staff’s proposal of 2 ppmv BARCT level for gas turbines using refinery gas. They proposed adding catalyst to the existing SCRs of the gas turbines to achieve 2 ppmv NOx. Their estimates are generally lower than the staff estimate since they assumed that more catalyst would be used rather than the addition of new SCRs. NEC’s estimates are compared to the staff estimate in Table C.8. 33

### 112 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table C. 8 - Comparison of Staff’s and NEC’s Estimates for Gas Turbines
No of Rating Current Incremental Emission Staff’s Estimate NEC’s Units (MW) NOx Reduction per Unit from PWV per Unit Estimate Level 2005 BARCT ($M) PWV per Unit (ppmv) (tpd) ($M) 1 59 5.7 0.21 15.7 (new SCR) 5.1 (add catalysts) 3 46 3-4 0.31 12.6 (new SCR) 4.0 (add catalysts) 2 30 6 0.20 8.9 (new SCR) 2.6 (add catalysts) 1 23 5.7 0.14 7.2 (new SCR) 2.0 (add catalysts) 4 83 2.5-3.5 0.60 4.8 (add catalysts) 7.1 (add catalysts) Total for all units 4.14 97.68 52.7



## Staff’s Recommendation

Staff recommends to set a new BA RCT level of 2 ppmv NOx for refinery gas turbines since NOx control technologies such as DLE/DLN, CLN, SCR with CO catalysts, SCR with ASC are commercially available and can beused together to achieve 2 ppmv NOx in a cost-effective manner. A level of 2 ppmv NOx is achieved -in-practice for a turbine/duct burner 1,7 MW cogeneration unit using SCR and ammonia slip cat alysts. An 83 MW cogeneration with SCR and CO catalysts was given a permit to construct since 2012 w ith a permit condition of 2 ppmv NOx.
In summary:

x Incremental Emission Reductions bey ond 2005 BARCT level: 4.14 tons per day

x Total Estimated Incremental Costs Range: $52.7 (NEC) - 97.68 M (Staff)

x Average Incremental Cost Effectiveness: 1,452 – 2,692 $/ton (DCF) and 2K – 4.5K $/ton (LCF)

### 113 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## References for Gas Turbines
1. Refinery Survey Information. SCAQMD 2013. 2. Alternative Control Techniques Document – NOx Emissions from Stationary Gas Turbines. EPA-453/R-93-007. January 1993. 3. Cost Analysis of NOx Control Alternatives fo r Stationary Gas Turbines. Contract No. DEFC02-97CHIO877. ONSITE SYCOM Energy Corpora tion. Prepared for U.S. Department of Energy. November 5, 1999.
4. SCR Costs Information from Manufacturer A. E-mails to Minh Pham on December 16, 2013 and March 12, 2014.
5. SCR Costs Information from Manufacturer B. E-mails to Minh Pham on November 25, 2013.
6. SCR Costs Information from Manufacturer C. E-mail to Refiner 10 on January 28, 2014. 7. Application and Engineering Evaluation for Permit to Construct of 85 MW Cogeneration. Email from R. Beshai to Minh Pham on November 7, 2013. 8. Costs Information and 2011 Fuel Gas Usage from Refinery 1. Email to Minh Pham on November 8 - 21, 2013. 9. Costs Information from Refinery 10. Email to Minh Pham from October 17, 2013 to January 31, 2014 10. Technology Characterization: Gas Turbines.Energy and Environmental Analysis. Prepared for Environmental Protection Agency ClimateProtection Partnership Division, Washington, DC. December 2008. 11. Reducing NOx and NH3 Emissions with Advanced SCR Technology. Rita Aiello, Kevin Doura, Mike Baran, Wilson Chu, PaulAnderson, Johnson Matthey. Paper #33233. A&WMA’s 107 th Annual Conference & Exhibition, June24-27, 2014, Long Beach California. 12. Catalytic Multi-Pollutant Abatem ent of Gas Turbine Exhaust. N. Jakobsson and H. JensenHolm. Environmental R&D and Environmental Catalyst. Haldor Topsoe. Downloaded from Haldor-Topsoe website in 2014. www.topsoe.com

. 13. Selective Catalytic Reduction of NOx Emission from Gas Turbines with minimal Impact on Plant Performance. H. Jensen-Holm and P. Li ndenhoff. SCR DeNOx Catalyst & Technology

### 114 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Department. Haldor-Topsoe. Download ed from Haldor-Topsoe Website in 2014. www.topsoe.com . 2 PPMV NOx 14. Dry Low NOx (DLN) Combustion Performance. www.ge-energy.com 3 PPMV 15. Latest Developments in Aero derivative Power Generating Systems. B. Naidu and P. Tinne. GE Aero-derivatives. Presentation at the SCAQMD. 2013 16. E-mail from B. Naidu to M. Pham on December 11, 2013. 17. Reduction of NOx and CO to Below 2 ppmv in a Diffusion Flame. V. Sahai and D.Y. Cheng. Proceedings of ASME Turbo Expo 2003. June 16-19, 2003. 18. Characteristics and Benefits of Simplified Combined Cycle. Electric Power Research Institute. EP-P32237/C15022. September 29, 2009. 19. Assessment of the Cheng Simplified Combin ed Cycle. Technical Update, December 2010. 20. CLN with SCR as an Emission Control Systemin CHP Plants Should Meet 2 ppmv NOx. Dr. Dah Yu Cheng, Ian Church, Ching-An Cheng. Paper #33051. A&WMA’s 107 th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 21. Costs information provided by Cheng Combus tion. E-mail from D. Cheng to Minh Pham on November 2013 – January 2014 22. CLN presentation to the SCAQMD staff, January 14, 2014.
23. Costs information on CLN. E-mail from Dr. Ch eng to Minh Pham on January 10 and February 5, 2014. 24. Combating NOx from Refinery Sources Using S CR. Haldor Topsoe. Presentation at the 2 nd Annual World Refining Technology Summit & Exhibition, 2010, Abu Dhabi. www.topsoe.com , posted online and downloaded in January 2014. 25. SCR and Zero-Slip TM Technology. T.W. Hastings of Cormetech, Inc. and A. Hattori of Mitsubishi Power Systems, Inc. Presentati on of June 17, 2003 Turbo Expo – Atlanta, GA. 95% SCR efficiency. Ten units less th an 2 ppmv NOx and 2 ppmv ammonia slip. 26. Dual Function Catalyst Promises High NOx Removal with Zero Ammonia Slip for Gas Turbine Applications. J.A. Rosin and H.S. Rosenberg. Power Engineering, September 2001, Vol. 105, Issue 9, page 76.

### 115 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

27. BASF NOxCat VNX & ZNX for Power Generati on and Ammonia Destruction Catalysts. www.catalysts.basf.com

. 28. Information on gas turbines from Refinery 5 to Minh Pham, December 3, December 17 and December 20, 2014. 29. SCAQMD engineering evaluation on Refinery 5 new cogeneration project. E-mail from Bob Sanford to Minh Pham, December 6, 2015. 30. E-mails from Refinery 5 to Minh Pham , December 3, 17, 20, 2013; January 16, 2014, and February 18 and 28, 2014. 31. Information from engineering evaluation on Re finery 7 Cogeneration unit. E-mail from Cynthia Carter to Minh Pham, February 27 and 28, 2014. 32. BASF NOx CAT VNX Catalyst an d Zeolite. BASFPublication 33. BARCT Analysis for SCAQMD NOx RECLAIM, Non-Confidential Report, Norton Engineering Consultants, November 26, 2014

### 116 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix D - Coke Calciner
Process Description
Tesoro operates the sole coke calciner in the SCAQMD. Coke calcining is a process to improve the quality and value of “green coke” produced at a delayed coker in a refinery. The green feed, produced by the nearby Carson Refinery, is screened and transported to the coke calcining facility by truck, where it is stored under cover in a coke storage barn. The screened and dried green coke is introduced into the high end of the rotary kiln, 3 ft diameter x 270 ft long, is tumbled by rotation, and moves down the kiln countercurrent to a ho t stream of combustion air produced by the combustion of natural gas or oil. The kiln temperatures are in a range of 2000 – 2500 degrees Fahrenheit. The green coke is retained in the kiln for approximately one hour to drive off the moisture, impurities, and hydrocarbon. After disc harging from the kiln, the calcined coke drops into a cooling chamber, where it is quenched with water, treated with dedusting agents for dust control, and carried by conveyors to storage tanks. Later, the calcined coke is transported by trucks to the Port of Long Beach for export, or is loaded into railcars for shipments to domestic customers. A simplified process diagram of the calc ining process is shown in Figure D.1. The coke calciner produces approx imately 400,000 tons per year of calcined products. This plant is a global supplier of calcined c oke to the aluminum industry, and they provide fuel grade coke to the fuel, cement, steel, calciner, and specialty chemicals businesses. 1 

## Emission Inventory

The 2011 NOx emissions from the coke calciner and current NOx outlet concentration are listed in Table D.1. The total 2011 emissions are 0.55 tons per day. The NOx outlet concentration at 65 ppmv is higher than the 2005 BARCT level of 30 ppmv (0.036 lb/mmBtu).

Table D. 1 - 2011 Emissions for Coke Calciner

Fac ID Device ID Device 2011 Emissions (lbs) Current NOx at 3% O 2 (ppmv) 2 C67 Afterburner 390,625 65 2 D20 Rotary Kiln 11,400 65 Total (tpd) 0.55

### 117 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Figure D. 1 - Coke Calciner Process (Reference 1) 

## Control Technology
The commercially available control technologies for NOx emissions for the coke calciner are LoTOx and UltraCat, two commerc ially available multi-pollutant control technologies for low temperature removal of NOx.

LoTOx TM Application

LoTOx TM stands for “Low Temperature Oxidation” process where ozone is used to oxidize insoluble NOx compounds to soluble NOx comp ounds. LoTOx is a low temperature operating system, meaning that it does not require heat input to maintain operational efficiency and enables maximum heat recovery of high temperature co mbustion gases. In addition, LoTOx can be used with a wet (or semi-wet) scrubber, and together the system becomes a multi-component air pollution control system that can reduce NOx, SOx and PM concurrently. There are more than 50applications engineered by Linde LLC. since 1 997, and more than two dozen applications with EDV TM scrubbers engineered by BELCO Dupont since 2007. 2-3 Applications in gas-fired and high sulfur coal-fired units met 2-5 ppmv. Current installations in refineries met 8-10 ppmv. The technology can be applied to coke calciner, and the manufacturer confirmed that LoTOx can be designed to achieve 2 ppmv NOx from current inlet concentrations of the coke calciner.

### 118 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

The 2010 SOx RECLAIM amendments set a BARCT le vel of 10 ppmv SOx for the coke calciner. It was determined that wet scrubbers engineered by BELCO, Tri-Mer and MECS were all feasible and cost effective. LoTOx application can be inte grated in any of these scrubbers to reduce NOx, SOx, PM and other toxic pollutants. The footprin t needed for scrubbers and associated equipment was estimated to be about 30 ft x 40 ft. The fac ility has not yet installed any scrubber since the adoption of the SOx RECLAIM amendments in 2010.

UltraCat TM Application UltraCat is also a multi-component air polluti on control technology developed by Tri-Mer. UltraCat catalyst filters are composed of fibrous ceramic materials embedded with proprietary catalysts that can remove NOx, SO 2 , PM, HCl, Dioxins, and HAPs. The optimal operating temperatures are approximately 350 to 750 degrees F. Aqueous ammonia injected upstream of the catalytic filters is used to remove NOx. NOx rem oval efficiency is about 95%. Dry sorbent such as hydrated lime, sodium bicarbonate or trona inject ed upstream of the catalytic filters is used to remove SO 2 , HCl, and other acid gases with a removal e fficiency of 90% - 98%. Particulate control to a level of 0.001 grains/dcsf and mercury control are also possible. UltraC at filters are arranged in a baghouse configuration with low pressure drop, about 5” water colu mn, and it has a reverse pulse-jet cleaning action (the filters are back flushed with air and inert gas to dislodge the particulate deposited on the outside of the filter tubes). Catalytic filter tubes are replaced every 5 to 10 years. The UltraCat catalytic filtering system is depicted in Figure D.2.

Figure D. 2 - Ultra-Cat Filters (Reference 5) [D2]

### 119 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Costs and Cost Effectiveness

LoTOx TM Application

Table D.2 contains costs information provided by LoTOx manufacturer. 4 Staff estimated the PWV using the equations below for the Disc ounted Cash Flow (DCF) method assuming 4% interest rate and 25-years life for the control devi ce. Staff applied a contingency factor of 1.5 to account for any additional costs that might occur. Incremental cost effec tiveness was estimated as follows for the DCF method: PWV = 1.5 x (TIC + (15.62 x AC)) (Equation 1) CE = PWV / (ER x 365 days x 25 years) (Equation 2)

Where: TIC = Total Installed Costs, $ AC = Annual Operating Costs, $ ER = Incremental Emission Reductions In December 2014, the PWV and CE for LoTOx appl ication were estimated to be $22 million and $10,347 per ton NOx reduced per DCF method as s hown in Table D.3. The CE would be $17,073 per ton NOx reduced per Levelized Cash Flow (LCF) method.

UltraCat TM Application

Table D.2 contains costs information provided by UltraCat manufacturer. 6 In December 2014, staff estimated the TIC based on the OAQPS EPA Guidelines, i.e. TIC = 1.86 * Equipment Costs. Staff also applied a contingency factor of 1.5 to ac count for any additional costs that might occur. The PWV assuming 4% interest rate and 25-year s life for the control device and the CE were estimated using Equations 1 and 2 shown above. The incremental emission reductions for UltraCat system were estimated to be 0.23 tpd NOx and 0.28 tpd SOx
In December 2014, the PWV and incremental cost effectiveness for UltraCat application were estimated to be $61 million and $13,071 per ton NOx and SOx reduced estimated using DCF method as shown in Table D.3. The incremental cost effectiveness would be $13 K per ton NOx and SOx reduced estimated with the DCF method.

### 120 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table D. 2 – Costs of LoTOx and Ultr aCat for Coke Calciner (December 2014)
2011 NOx emissions 0.55 tons per day NOx Current NOx concentration 64.95 ppmv NOx 2005 NOx BARCT level 30 ppmv NOx 2010 SOx BARCT level 10 ppmv SOx 2015 BARCT proposed level 2 ppmv NOx 2011 NOx emissions at 30 ppmv BARCT 0.25 tpd 2011 NOx emissions at 2 ppmv BARCT 0.02 tpd Incremental NOx emission reductions 0.23 tpd Flue Gas Temp 450 degrees F Flue Gas Flow 6,806,770 dscfh (113,446 scfm) Stack Oxygen 5% Stack Moisture 29.8% Coke Burned 81,471 tons per year LoTOx Application for 2 ppmv NOx (97% control) Total Installed Costs $6,250,000 Operating Costs $544,300 per year LoTOx Application for 5 ppmv NOx (92% control) Total Installed Costs $6,200,000 Operating Costs $516,800 per year Ultra Cat Application for 2 ppmv NOx (97% control) Capital Costs of Emission Control $7,531,774 Operating Costs – Utility, Catalysts, Labor, $1,721,490 per year Maintenance Filters replacement frequency 5 years at $215,600 per year

Table D. 3 - Cost and Cost Effectiveness Estimates for Coke Calciner (December 2014)
Emission Reductions PWV ($M) Incremental CE ($/ton) LoTOx 0.23 tpd NOx 22.13 10,374 UltraCat 0.23 tpd NOx + 0.28 tpd SOx 61.35 13,071

### 121 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Consultant’s Analysis for LoTOx and Staff’ s Revised Estimates for LoTOx and UltraCat NEC suggested that a BARCT level of 2 ppmv was not feasible, and recommended 5 ppmv – 10 ppmv BARCT level for the coke calciner. NEC al so suggested that a factor of 1.86 to estimate TIC and an adjustment of 1.5 were not conservativ e enough since space was extremely challenging at the coke calciner facility. A factor of 4.5 – 4.6 was more reasona ble. Staff concurred with NEC recommendation and re-estimated the PWVs for the Ultra-Cat application as shown in Table D.4.

Table D. 4 – Revised Cost and Cost Effectiveness Estimates for Coke Calciner (March 2015)
Staff’s Estimates Using Factor of 4.5 NEC’s Estimates BELCO Tri-Mer BARCT Level 10 ppmv 92% control 10 ppmv Incremental Reductions (tpd) 0.17 0.17+0.28=0.45 0.17 PWV ± 50% ($M) 54.29 91.17 39.50 Cost Effectiveness DCF ($/ton) $35K/ton $22K/ton $25K/ton Cost Effectiveness LCF ($/ton) $58K/ton $36K/ton $42K/ton 

## Staff’s Recommendation
Staff recommends setting a BARCT level of 10 ppmv NOx for coke calciners because NOx control technologies such as LoTOx and UltraCat are comme rcially available to ach ieve this level in a cost-effective manner. 2014 BARCT NOx = (0.08 tpd)(2000 lb/ton)(365 days/yr)/(81,471 ton coke/yr) = 0.8 lb/ton coke

x Total incremental emissi on reductions beyond 2005 BARCT: 0.17 ton per day

x Total incremental costs: $39.5 million - $91 million

x Total incremental cost effectiveness: $22- $35 K/ per ton (DCF) or $36 - $58K/ton (LCF)

### 122 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## References for Coke Calciner
1. Staff Report of Proposed Amendments to SOx RECLAIM. Agenda 37 of the SCAQMD Governing Board Meeting. November 5, 2010.

2. LoTOx TM – Novel NOx Control Solution. Naresh J Suchak, Ph.D., Monica Caldwell, Peter Studer, Frank R Fitch, Ph.D., Li nde Gases. Paper #33612. A&WMA’s 107 th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 3. LoTOx NOx Reduction Technology Insta llation List. Dupont BELCO Clean Air Technologies, dated May 2013. 4. Costs for LoTOx Application to Meet 2 ppmv NOx for 3 FCCUs and Coke Calciner in the SCAQMD. Email of information provided by LoTOx manufacturer to Minh Pham. December 12, 2013 and January 20, 2014. 5. Tri-Mer UltraCat Catalytic Filters – Brochure downloaded from www.trimer.com in January 2014. 6. Costs for UltraCat Application to Meet 2 ppmv NOx for Coke Calciner in the SCAQMD. Emails of information provided to Mi nh Pham. November 8, 2013 and May 21, 2014. 7. BARCT Analysis for SCAQMD NOx RECLAIM, Non-Confidential Report, Norton Engineering Consultants, November 26, 2014

### 123 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix E - Sulfur Recovery Units/Tail Gas Incinerators Process Description
A sulfur recovery unit and tail gas treatment unit (SRU/TGTU) at the refineries include a Claus unit followed by an amine absorption unit to rec over the sulfur from various gaseous. The SRU (Claus unit) consists of a reactor and series of converters and condensers. Approximately 95% of sulfur from the gaseous streams is recovered after passing through the SRU. The tail gas is then sent to an amine absorption unit, or diethanol amine (DEA), SCOT, Wellman-Lord, and FLEXSORB to absorb and recover the remaining sulfur. Approximately 99% or the remaining sulfur is absorbed and recovered after the amine units. The tail gas is then vented to a thermal (or catalytic) oxidizer (incinerator) where the residual H 2 S in the tail gas is oxidized to SO 2 before emitting to the atmosphere. The refinery SRU/TGTU s including their incinerators are classified as major sources of NOx and SOx. Since the interception of the RECLAIM in 1993 until 2010, no Best Available Retrofit Control Technology (BARCT) standards havebeen established for the SRU/TGTUs and incinerators. The 2010rule amendment included a new BARCT level fo r SOx at 5 ppmv, 0% O2. At that time, it was determined that Refineries 1, 5, and 6 could retrofit their SRU/TGTUs cost-effectively with wet gas scrubbers (WGS) to further reduce SOx emissions. The construction time was estimated to be about 3 years. 1 As of today, Refineries 1, 5 and 6 did not retrofit any of their existing SRU/TGTUs, instead they selected to purchase RECLAIM Trading Credits or reduce SOx elsewhere in the refinery to comply with their facility emission caps. In 2011, Refinery 5 installed a new SRU/TGTU at their refinery and ev aluation of the performance is ongoing. 

## Emission Inventory

The 2011 NOx emissions from the SRU/TGTUs a nd incinerators in the SCAQMD and their current NOx outlet concentration are shown in Table E.1. The total 2011 emissions are 0.43 tons per day. The NOx concentrations at the stack vary widely from 6 ppmv to 70 ppmv. It should be noted that their SOx emissions also vary widely from 20 ppmv to 150 ppmv.

### 124 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table E. 1 - 2011 Emissions for SRU/TG Incinerators

Unit Fac ID Device ID Device 2011 Emissions (lbs) Existing NOx @ 3% O2 1 9 1260 INCINERATOR 7,696 66.81 2 6 952 INCINERATOR 41,066 6.57 3 5 911 INCINERATOR 28,379 29.00 4 5 913 HEATER 12,087 29.00 5 5 927 INCINERATOR 14,276 27.00 6 5 929 HEATER 6,080 29.00 7 5 955 INCINERATOR 40,313 29.83 8 5 957 HEATER 13,035 29.83 9 1 910 INCINERATOR 42,273 28.07 10 1 2413 INCINERATOR 22,337 18.33 11 10 175 INCINERATOR 5,674 45.89 12 3 54 INCINERATOR 13,115 55.00 13 3 56 INCINERATOR 4,931 55.00 14 7 436 INCINERATOR 8,030 18.68 15 7 456 INCINERATOR 7,025 31.85 16 8 294 thermal INCINERATOR 49,563 32.00 17 8 292 catalytic INCINERATOR 1,010 not reported Total (tpd) 0.43 

## Control Technology

Commercially available control technologies for NO x emissions are Selectiv e Catalytic Reduction (SCR) and LoTOx. KnowNOx has been installed attwo locations in the U.S. however has not yet been tested in any refinery applications. While SCR is considered a high temperature NOx reduction technology, LoTOx and KnowNOx are known for low temperature multi-pollutant control systems since they can be integrally connected with a WGS to reduce NOx, SOx, PM, VOCs, HAPs, and other toxic compounds.
Selective Catalytic Reduction For the past two decades, SCR technology has beenused successfully to control NOx emissions. The technology is considered mature and commerci ally available. The advanced SCRs can be designed to reduce 95%-98% NOx emissions from the SRU/TGTUs and incinerators and achieve 2 ppmv NOx while maintaining a low ammonia slip of less than 5 ppmv. 3-14

### 125 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

LoTOx TM Application

LoTOx TM stands for “Low Temperature Oxidation” process where ozone is used to oxidize insoluble NOx compounds to soluble NOx compounds which can be subsequently removed by absorption in caustic solution, lime or limestone. Please refer to Appendix A for details. There are more than 50 LoTOx applications engineeredby Linde LLC., and two dozen applications engineered by BELCO of Dupont for refinery FCCU applications. 15, 22 While BELCO’s expertise is in the refinery FCCUs, its sister company MECS has engineered more than two dozen DynaWave scrubbers specifically designed for refinery SRU/TGTUs. Figure E.1 shows a schematic for a DynaWave scrubber. Figure E-2 contains a schematic for LoTOx process incorporated into the DynaWave scrubber. Currently, LoTOx applications in the FCCU applications have achieved 8 ppmv - 10 ppmv NOx, and 2 ppmv – 5 ppmv NOx in gas-fired and high sulfur coal-fired units. 15, 22 LoTOx technology can be incorporated to the refinery SRU/TGTUs’ incinerators and designed to achieve a level of 2 ppmv NOx outlet concentrations. 24
Table E.3 has a list of the DynaWave installations in the U.S. 25 This is not an inclusive list. In addition to refinery SRU/TGTU applications, DynaWave scrubber s are used in numerous other industrial applications such as sulfuric acid plan ts, coke calciner, metallu rgical plants, secondary aluminum or copper smelters, coal fired heaters a nd boilers, sulfur pits, platinum recovery plants, cement kilns, meat rendering plan ts, and medical waste incinerato rs. DynaWave scrubbers have been used in the industries since 1987. A BARCT level for SOx was established at 5 ppmv, 0% O 2, annual average in 2010. In 2011, Refinery 5 installed a new SRU/TGTU with a Dy naWave scrubber to meet a short-term BACT standard of 10 ppmv. The most recent source test data shows that the DynaWave scrubber meets <1 ppmv SOx, corrected to 0% O 2 . Thus, concurrent reductions of NOx and SOx are feasible and cost-effective using a DynaWave and LoTOx combination application.

### 126 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Figure E. 1 - DynaWave Scrubber (Reference 23)

Figure E. 2 - Ozone Generation Process (Reference 23)

### 127 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table E. 2 - List of DynaWave Scrubber Installations for SR/TGTUs

Company/Location StartUp Date Exit Gas ACFM Application
KiOR 2012 82,135 BioRefinery FCC Off Gas Mississippi Quench, SO 2 and Particulate Calumet 2010 15,545 40 LTPD SRU Tail Gas Clean Up Louisiana SO 2 removal with NaOH Chevron 2013 27,800 SRU SCOT Tail Gas Clean Up California SO 2 removal with NaOH Sinclair 2009 59,603 FCC Off Gas Oklahoma Quench, SO 2 and Particulate Wyoming Refining 2011 57,746 FCC Off Gas Wyoming Quench, SO 2 and Particulate Pasadena Refining 2008 2,200 S Zorb Off Gas Texas SO 2 removal with NaOH ConocoPhillips 2006 6,700 S Zorb Off Gas Illinois PM and SO2 removal with NaOH Sinclair 2006 9,000 25 LTPD SRU Tail Gas Clean Up Oklahoma SO 2 removal with NaOH Marathon Ashland 2008 10,100 33 LTPD SRU Tail Gas Clean Up Texas SO 2 removal with NaOH Sinclair 2005 12,830 47.5 LTPD SRU Tail Gas Clean Up Wyoming SO 2 removal with NaOH Sinclair 2005 5,700 18 LTPD SRU Tail Gas Clean Up Wyoming SO 2 removal with NaOH ConocoPhillips 2005 2,000 S Zorb Off Gas Louisiana SO 2 removal with NaOH Navajo 2003 100,000 FCC off gas NaOH scrubber for SO 2 and PM New Mexico ConocoPhillips 2003 3,300 S Zorb Offgas Washington SO 2 removal using NaOH Unocal Refining 1993 17,300 Spent sulfuric acid plant California Hess Oil St. Croix 1993 9,400 Spent sulfuric acid plant Virgin Islands Gas cleaning for new plant Sun Refining 1991 2,000 H2S and sour water incinerator Pennsylvania Particulate and SO3 removal BP 1990 130,000 Coke calciner Washington PM/SO2 removal with soda ash

### 128 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

KnowNOx TM Application In lieu of using ozone to convert NO and NO 2 to N 2 O 5 and HNO 3 , the KnowNOx technology uses chlorine dioxide ClO 2 . The conversion reactions (Reactions 12 and 13) are in the gas phase, which can occur much faster than the liquid phase reactions with ozone (Reactions 5 and 6). It takes less than 0.5 seconds to achieve 99.8% or more convers ion. The reactions require a smaller vessel in relative to the LoTOx reaction chamber. In addition, the KnowNOx process can simultaneously reduce NOx, SO 2 , PM and other contaminants. 26-28

5 NO + 2 ClO 2 + H 2 2ĺ1 O 2 + 2 HCl (Reaction 12 - Gas Phase) 5 NO 2 + ClO 2 + 3 H 2 2 ĺ+12 3 + 2 HCl (Reaction 13 – Gas Phase) 5 SO 2 + 2 ClO 2 + 6 H 2 2ĺ+ 2 SO 4 + 2 HCl (Reaction 10) The conceptual layout for the KnowNOx process is shown in Figure E.3. It includes a three-stages scrubbing system: SO 2 is scrubbed at the 1 st stage with a DynaWave scrubber, ClO 2 injected to the 2nd stage converts NO and NO 2 to HNO 3 and other soluble salts, and H 2 S generated in the 2 nd stage is converted to soluble salts in the 3 rd stage. The KnowNOx technology has been installed at two locations in the U.S., however, it has not ye t been tested in any re finery applications, and may not yet have been proven at full scale operations.

Figure E. 3 – KnowNOx Process (Reference 28)

### 129 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Costs and Cost Effectiveness
Selected process conditions and the outlet NOx concentrations of the SRU/TGTUs at the refineries in the SCAQMD are listed in Table E.3. To obta in control equipment cost information, staff provided the manufacturers with the information for the three scenarios listed in Table E.4. These scenarios reflect the units with highest emissions and flue gas flow rates from the 17 SRU/TGTUs/incinerators in the SCAQMD. Staff estimated the PWV for the control system using Equation 1 below assuming 4% interest rate and a 25-years life for the control device: PWV = (Contingency Factor) x (TIC + (15.62 x AC) + (2.52 x CR)) (Equation 1) Where: PWV = Present Worth Value, $ TIC = Total Installed Costs, $ AC = Annual Operating Costs, $ CR = Catalyst Replacement every 5 years Contingency factor = 1.5 Staff used the factors in the EPA OAQPS Guidelines to estimate the TIC and a contingency factor of 1.5 was added to the TIC and AC to account for operational uncertaintie s. CE was estimated as shown in Equation 2 using the DCF method. Fo r comparison, the incremental cost effectiveness would be about 1.65 higher if it was calculated using the LCF method: CE = PWV / (ER x 365 days x 25 years) (Equation 2)

Where: CE = Incremental Cost Effectiveness, $/ton PWV = Present Worth Value, $ ER = Incremental Emission Reductions, tpd Costs for SCRs

Manufacture A’s estimates are summarized below: 13

x It is feasible to achieve 2 ppmv NOx and 5 ppmv ammonia slip,

x All three scenarios would result in about the same costs,

x Costs for SCR catalysts would be about$600,000 and installation costs about $600,000,

x Add costs for heat exchangers in Scenario 1 and 2, and

x Inlet NOx could be higher but would not affect the overall cost estimates.

### 130 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table E. 3 - Process Information and NOx Emissions for SRU/TG Incinerators in SCAQMD

Unit Fac ID Device ID Device Max Rating (mmbtu/hr) Flue Gas Flow rate

(dscfm) Flue Gas Temp (degree F) Existing NOx (ppmv) 1 9 1260 INCINERATOR 36 66.81 2 6 952 INCINERATOR 100 34,640 1,080 6.57 3 5 911 INCINERATOR 30 12,500 515 29.00 4 5 913 HEATER 25 12,500 515 29.00 5 5 927 INCINERATOR 30 12,500 570 27.00 6 5 929 HEATER 25 12,500 570 29.00 7 5 955 INCINERATOR 58 14,500 520 29.83 8 5 957 HEATER 41 14,500 520 29.83 9 1 910 INCINERATOR 45 32,167 1,260 28.07 10 1 2413 INCINERATOR 40 27,167 1,292 18.33 11 10 175 INCINERATOR 10 45.89 12 3 54 INCINERATOR 52 55.00 13 3 56 INCINERATOR 45 55.00 14 7 436 INCINERATOR 20 18.68 15 7 456 INCINERATOR 20 31.85 16 8 294 thermal INCINERATOR 28 23,284 32.00 17 8 292 catalytic INCINERATOR 15

Table E. 4 – NOx and SOx Performance of SRU/TG Applications in SCAQMD

Scenario 1 Scenario 2 Scenario 3 Refinery 6 Refinery 1 Refinery 5 Incinerator Rating 100 mmBtu/hr 45 mmBtu/hr 100 mmBtu/hr (note) Average flue gas flow rate 36,000 dscfm 32,000 dscfm 14,500 dscfm Temperature 1,100 degrees F 1,200 degrees F 520 degrees F O2 % 2.5% 6% - 8% 4% Current NOx concentration 21 ppmv 28 ppmv 30 ppmv Current SOx concentration 40 ppmv 75 ppmv 20 ppmv Note: Incinerator 58 mmBtu/hr and heater 41 mmBtu/hr are vented to a common stack

### 131 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Manufacturer B’s estimates are summarized below: 14

x It is feasible to achieve 2 ppmv NOx and 5 ppmv ammonia slip,

x SCR costs for Scenario 1 and 2 were estimated to be about $461,000 for SCR at 80% NOx control efficiency. SCR costs for S cenario 3 would be about 10% less than Scenario 1 and 2.

x Costs for a system at 90% control efficiency would be about 5% higher than the costs for a system at 80% control efficiency.

x Costs for a system with 95% control efficiency would be about 10% higher than the costs for a system at 80% control efficiency.

x Estimated costs would not vary with inlet NOx concentration

x SCR footprint and dimension:
o Catalysts with 1 layer and 1 module for a system with 85% control efficiency. Add 3 in of catalysts for a 95% control efficiency system
o Add 2 ft in each direction for structural steel, and 6” for insulation
o SCR overall dimension: 15 ft x 15ft x 15 ft

x Heat exchanger would be required for Scenario s 1 and 2 to lower the temperatures to the optimum temperatures of about 750 degrees F
o Heat exchanger would cost about $100,000
o Dimension for a horizontal flow heat exchanger: 6 ft Dia x 6ft - 10 ft L.

x Ammonia usage (19% aqueous ammonia):
o 11.1 lb/hr for 80% removal, 12.1 lb/hr for 90% control, 12.6 lb/hr for 95% control
o About $82,000 per year NH 3 costs and $40,000 miscellane ous for a 95% control
o Dimension of 2000-gallons NH 3 storage tank: 4 ft D x 24 ft L, or 6 ft D x 10 ft L.
o Ammonia storage tank costs $15,000 (30 days supply)

x Catalyst replacement would be every 5 years. Replacement frequency would depend on actual flue gas constituents and could be guaranteed for a turnaround cycle.

Costs for LoTOx TM Applications MECS’s cost estimates for LoTOx system to reduce NOx emissions are shown in Table E.5. MECS also provided costs for DynaWave and Lo TOx in one system to reduce both NOx and SOx emissions as shown in Table E.5. 24

### 132 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table E. 5 – Cost Information Provided by MECS

Scenario 1 Scenario 2 Scenario 3 LoTOx Dynawave LoTOx Dynawave LoTOx Dynawave LoTOx LoTOx LoTOx Inlet Temp, degrees F 1,100 1,100 1,200 1,200 520 520 Inlet Flow, scfm 38,710 38,710 34,409 34,409 15,761 15,761 Outlet Temp, degrees F 158 158 161 161 139 139 Outlet Flow, scfm 52,782 52,782 48,329 48,329 18,021 18,021 Total Installed Costs, $ 5,666,000 8,432,000 5,605.000 8,311,000 4,903,237 6,907,000 Operating Costs, $/yr 89,356 260,600 98,713 276,110 47,000 73,650

Costs for KnowNOx TM Applications Costs provided by KnowNOx for its system to reduce only NOx emissions are shown in Table E.6. KnowNOx also provided costs for DynaWave scrubber in combination with its technology to reduce both NOx and SOx emissions. 29

Table E. 6 – Cost Information Provided by KnowNOx

Scenario 1 Scenario 2 Scenario 3 KnowNOx Dynawave KnowNOx KnowNOx Dynawave KnowNOx KnowNOx Dynawave KnowNOx Inlet Flow, scfm 36,000 36,000 32,000 32,000 14,500 14,500 Total Installed Costs, $ 1,420,225 4,220,226 1,398,286 4,198,286 1,401,825 3,402,226 Operating Costs, $/yr 108,284 289,936 112,957 295,948 198,729 227,337
In 2014, staff estimated that SCRs, LoTOx and KnowNOx would be cost-effective for 10 SRU/TGTUs (out of 17 units) at Refineries 1, 5, 6 and 8. The PWVs for SCRs, LoTOx and KnowNOx were estimated to be $48.7 M, $68 M and $39 M respectively. The cost effectiveness for the 7 SCRs was estimated to be $15 K pe r ton NOx reduced (DCF) and $25 K per ton NOx reduced (LCF) as shown in Table E.7.
Consultant’s Analysis for SCRs and Staf f’s Revised Estimates for SCRs and LoTOx NEC confirmed that the 2 ppmv proposed BARCT le vel is feasible for the refinery SRU/TG incinerators. However, the consultants indicat ed that the factor of 1.86 from the EPA OAQPS Guidelines was low and suggested staff used a factor of 4.5. NEC also recommended using SCRs

### 133 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 with 3 layers of catalysts and added the cost s of waste heat boilers, new ammonia tanks and associated equipment. A comparison of NEC’ s and staff’s estimates is shown in Table E.7.

Table E. 7 - Comparison of SCR Costs Estimated by Staff and NEC for SRU/TGTUs (December 2014)

Staff’s Estimates NEC’s Estimates for SCRs for SCRs PWVs for SCRs $ 48.7 M $ 96.4 M Cost Effective Units 10 9 Emission Reductions 0.35 tpd 0.32 tpd Cost Effectiveness (DCF) 15,233 $/ton 33,014 $/ton

Staff revised the cost estimates using the fact or of 4.5 recommended by NEC. The revised estimates are shown in Table E.8. Per these revised estimates, there would be 9 cost effective SRU/TG units with a total incremental emissi on reductions of 0.32 tpd at PWVs of $82.5 M for SCRs or $105.8 M for LoTOx applications.

Table E. 8 - Revised Cost and Cost Effectiveness Estimates for SCRs and LoTOx for SRU/TGTUs (March 2015)

Fac ID Dev SCR LoTOx AQMD

($M) Reductions (tpd) AQMD CE ($/ton) AQMD ($M) Reductions (tpd) AQMD CE ($/ton) 6 D952 5 911/913 5 927/929 5 955/957 1 910 1 2413 8 294 16.2 11.3 11.3 11.3 17.3 16.9 15.2 0.05 0.05 0.03 0.07 0.06 0.03 0.06 33,298 23,491 46,697 17,818 34,379 63,593**

25,805 22.7 18.9 18.9 18.9 22.7 22.7 22.7 0.05 0.05 0.03 0.07 0.06 0.03 0.06 46,458 39,321 78,167* 29,826 45,127 85,404**

38,490Total for costeffective units 82.5 0.32 28,270 105.8 0.29 39,963

* this unit was cost effective using SCR t echnology thus was included in the revised analysis. ** this unit was not cost effective using either SCR or LoTOx thus was not included in the revised cost analysis.

### 134 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Staff’s Recommendation

Staff recommends to set a new BARCT level of 2 ppmv NOx for SRU/TG incinerators (95% control efficiency) because NOx control technol ogies such as SCR and LoTOx (or KnowNOx) with DynaWave scrubbers are commercially available and can de designed to achieve 2 ppmv NOx in a cost-effective manner.
In summary:

x Incremental Emission Reductions beyond 2005 BARCT level: 0.32 tons per day

x Number of cost effective units: 9

x Total Incremental Costs: $83 M ± 50% with SCRs - $106 M ±50% with LoTOx

x Average Incremental Cost Effectiveness (DCF method):
o $28K per ton NOx reduced with SCRs
o $40K per ton NOx reduced with LoTOx applications

x Average Incremental Cost Effectiveness (LCF method):
o $46K per ton NOx reduced with SCRs
o $66K per ton NOx reduced with LoTOx applications.

### 135 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## References for SRU/TG Incinerators

1. Staff Report of Proposed Ame ndments to SOx RECLAIM. Agenda 37 of the SCAQMD Governing Board Meeting. November 5, 2010. 2. EPA Air Pollution Cost Manual, Section 4 – NOx Controls, EPA/452/B-02-001, Sixth Edition, January 2002. 3. Reducing NOx and NH3 Emissions with Advanced SCR Technology. Rita Aiello, Kevin Doura, Mike Baran, Wilson Chu, PaulAnderson, Johnson Matthey. Paper #33233. A&WMA’s 107 th Annual Conference & Exhibition, June24-27, 2014, Long Beach California. 4. UltraCat Catalytic Filters Remove PM, SO 2 , HCl, NOx, Dioxins and HAPs. NOx Control as Low as 350 degrees F – TriMer’s brochure – www.tri-mer.com

. 5. Combating NOx from Refinery Sources Using S CR. Haldor Topsoe. Presentation at the 2 nd Annual World Refining Technology Summit & Exhibition, 2010, Abu Dhabi. www.topsoe.com , posted online and downloaded in January 2014. 6. Information posted online at the we bsite for Mitsubishi and Cormetech, www.cormetech.com/non-reductionh.htm , and www.mhpowersystems.com/scr.html , downloaded on January 2014. 7. SCR and Zero-Slip TM Technology. T.W. Has tings of Cormetech, Inc. and A. Hattori of Mitsubishi Power Systems, Inc. Presentati on of June 17, 2003 Turbo Expo – Atlanta, GA. 8. Dual Function Catalyst Promises High NOx Removal with Zero Ammonia Slip for Gas Turbine Applications. J.A. Rosin and H.S. Rosenberg. Power Engineering, September 2001, Vol. 105, Issue 9, page 76. 9. Optimization of Ammonia Source for SCR Applications. R. Salib and R. Keeth of Washington Group International. Paper Po ster Session No. 46. (no date) 10. Comparison of Urea Based Ammonia to Liquid Ammonia Systems for NOx Reduction Applications. J. E. Fisher, WAHLCO, Inc. 11. Comparison of Urea, 19% Aqueous Ammonia, a nd Anhydrous Ammonia Operating Costs. of Canyon Energy Project. D. Kirk of Fuel Tech Inc. to C. McFarlin of California Energy Commission, September 3, 2008.

### 136 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

12. Influence Factors and Control Research on A mmonium Bisulfate Formation in the Process of Selective Catalytic Redu ction. S. Ma et.al., North China Electric Power University. Journal of the Air & Waste Manuscript Paper UAWM-2013. 13. SCR Costs Information from Manufacturer A. E-mail to Minh Pham on May 5, 2014. 14. SCR Costs Information from Manufacture B. E-mails to Minh Pham on May 8 and May 14, 2014.
15. LoTOx TM – Novel NOx Control Solution. Naresh J Suchak, Ph.D., Monica Caldwell, Peter Studer, Frank R Fitch, Ph.D., Li nde Gases. Paper #33612. A&WMA’s 107 th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 16. Meeting Tighter NOx Emission Rules – A Low Temperature Oxidation Technology Uses Ozone to Remove Very Low Leve ls of Nitrogen Oxide from Refi nery Gases. S. Harrison, N. Suchak, F. Fitch, Linde Gases. www.digitalrefining.com/article/1000954 . PTQ Q3 2014 17. Wet Scrubbing-based NOx Control Using Lo TOx Technology – First Commercial FCC StartUp Experience. Nicholas Confuorto of BE LCO Technologies, Jeffrey Sexton of Marathon Petroleum Company LLC. www.digital refi ning.com/article/1000812. September 2007 18. Preparing Wet Scrubbing Systems for a Future with NOx Emission Requirements. S. Eagleson and N. Confuorto, BELCO Technologies Corporation, www.digitalrefining.com/article/100833 . September 2013. 19. Low Temperature Oxidation System. California Air Resources Board Grant Number ICAT 99-1. www.arb.ca.gov/research/icat/projects/boc.htm#

. 20. Pilot-Scale Studies on NOx Removal from Flue Gas via NO Oxidation and Absorption into NaOH Solution. M. Jakubiak, W. Kordylewski. Wroclaw University of Technology, Faculty of Mechanical and Power Engineering, Institute of Power Engineering and Fluid Mechanics, Poland.
21. Acid Gas Scrubber for Muti-Pollutant Reduction. Nicholas Confuorto, BELCO. Institute of Clean Air Companies (ICAC) - Emission Control and Measurement Workshop. March 24-25, 2010. 22. LoTOx NOx Reduction Technology Installation List. Dupont BELCO Clean Air Technologies. May 2013. 23. MECS Presentation to SCAQMD. S. Whitlo ck, S. Myer of MECS Dupont. June 4, 2014.

### 137 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 24. Costs for LoTOx Applications from MECS. Email from Stephen Whitlock to Minh Pham. May 28, 2014. 25. DynaWave Scrubber Installation List. Email from S. Whitlock of MECS to Minh Pham. September 15, 2014. 26. Pacific Rim Design & Devel opment NOx Control Technology. Presentation to SCAQMD. D. Schwartzel of Dupont. 2013. 27. NOx Scrubbing Technology Breakthrough. Confidential Material. R. Richardson of KnowNOx. November 2013, 28. KnowNOx Presentation to SCAQMD. R. Richardson of KnowNOx. June 4, 2014. 29. Costs for KnowNOx Technology. E-mailsfrom R. Richardson to Minh Pham. June 2, 2014, and July 29, 2014. 30. BARCT Analysis for SCAQMD NOx RECLAIM, Non-Confidential Report, Norton Engineering Consultants, November 26, 2014.

### 138 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix F - Comparative Analyses for FCCUs
This appendix provides a comparison of the selective catalytic reduction (SCR) design configuration, total inst alled cost (TIC) calculation and present worth value (PWV) estimation methodologies used in the staff and NEC cost effe ctiveness calculation for the FCCUs. Table F.1 summarizes the basic comparison. Variations in the SCR size, cost assumptions, TIC and PWV estimation methodology are provide in a side by side comparison for evaluation.
Table F.1 - Comparison of Staff and NEC Control Equipment Designs, TIC and PWV Estimation Methods Staff's Design NEC's Design SCR Configuration 2-Catalyst layers 3-Beds: 1-reserve 3-Catalyst layers 3-Beds: all used Cost Models SCR costs directly provided by Refinery 1 (2 catalyst layers) and the manufacturers (2- catalyst layers) SCR cost for Refinery 5, 6 and 7 scaled to Refinery-1 based on flow rate. SCR cost for Refinery 4 and 9 provided directly by the manufacturers.E SCR cost provided by vendor (2 catalyst layers 12.8 feet per second). SCR vendor based costs curve (scaled for 3-layers, 10 feet per second) With NEC modifications and refinery input including:

x 1.35 bid conditioning factor,

x 1.75 labor factor, and

x 4.5 TIC factor Additional Costs Waste Heat Boiler Modifications, New CEMS, NH3 Storage Refinery Cost Application Refinery-1 Refinery-4 & 9 Refinery-5 Refinery-6 Refinery-7 All Refineries Refinery -1 data EPA Methodology with 1.5 contingency for PWV. NEC additional costs assumed in the contingency factor. Scaled to Refinery-1 Scaled to Refinery-1 Scaled to Refinery-1 SCR cost provided by manufacturer (2 catalyst layers) with NEC additional costs included. N/A Cost Curve

Cost Curve Cost Curve Cost Curve

Summary of Staff’s Approach Staff presented two approaches to estimate the SCR PWV for the 6 FCCUs operating in the Basin. (Note: two FCCUs are not controlled using SCRs). The first approach estimated PWV using data directly obtained from Refinery1 to establish PWV, while 3 additional SCR PWV were scaled from the Refinery 1 estimate. Two additional SCR PWV profiles were estimated using manufacturer provided cost information and the EP A cost model with a 150 percent contingency.

### 139 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The second approach used the NEC model for th e manufacturer’s SCR desi gned for 2-catalyst layers. The two methods provided a range of PWV and CE as reported in Appendix A. Approach #1

x Refinery 1 submitted capital costs and annual operating costs for their FCCU SCR in 2013. The FCCU SCR was installed in 2003 with 2 layers of catalysts and 1 spare layer and achieved 2 ppmv NOx.

x Using the cost information submitted directly by Refinery 1 to estimate the PWV would result in $41 M. Using the NEC equation (derived for a 3-catalyst layer SCR from data provided by a manufacturer) the PWV would result in $52 M. The PWV estimated based on NEC’s approach and equation would be about 26% high er than that estimated using the actual costs submitted by Refinery 1.

x Staff scaled the Refinery 1 SCR PWV cost usin g the of Refinery 1 SCR and the ratios of their appropriate inlet flue gas flow rates to the 0.7 power to project PWV for Refineries 5, 6, and 7.

x PWV for Refineries 4 and 9 was estimated using SCR manufacturer cost data and the U.S. EPA Guideline approach with a 150 percent contingency markup. Approach #2 Staff used the NEC approach to develop a cost curve based on the SCR manufacturer’s design of 2-catalyst layers. The NEC cost assumptions included:
o 1.35 for a bid conditioning factor
o 1.75 adjustment for labor
o 4.5 factor to relate the equipment costs to a TIC
o Staff added the NEC estimated costs of a waste heat boiler, new CEMS, and costs of ammonia storage tank.
PWV estimated for 2-catalyst layers vs. 3-catalyst layers A comparison of the PWV estimates calculated for Refinery 9 using the manufacturer 2-layer SCR model (with and without selected cost markups ) and the NEC 3-layer SCR model and the EPA methodology is presented in Table F.2.

### 140 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table F. 2 - Comparison of Cost Estimates for FCCU’s SCR

NEC's Manufacturer's EPA Design Design (note) Methodology Layers of catalysts 3 2 2 2 2 with 50% 1.35 Markup Yes Yes No Yes No Contingency 1.75 Markup Yes Yes Yes No No Total Installed Costs , $M 31.6 26.4 21.5 18.3 15.5 16.13 PWV, $M 39 32 27 24 21 19 Note: The TIC include the costs of SCR provided by vendor to NEC ($1.78 M) for a FCCU with a feed rate of 60 thousand barrels, the costs of waste heat boiler ($4.5 M) estimated by NEC, the costs of CEMS ($1.5 M) estimated by NEC, the costs of ammonia storage tank ($1.5 M) estimated by NEC, and annual operating costs estimated by NEC. The PWV for the manufacturer’s design with no markup ($21 M) was only 10% more than staff’s estimates using the EPA methodology. With equivalent markup fa ctors applied, the manufacturer’s 2-layer model was a pproximately 22 percent lower in cost than the 3-layer model. This compares well with the 26 percent PWV adjustment between the NEC 3-catalyst layer model and staff’s estimate for the 2-layer SCR noted for Refinery 1 in Approach #1. Also, for the EPA methodology, staff used a 50% contingency factor to account for the uncertainty in the complex refinery environment compared to the EPA OAQPS Guidelines recommended a level of 30%. The cost curve described in Approach #2 was used estimate the PWV of the SCR system with two NEC markup factors for an SCR provi ded by vendor with 2 layers of catalysts, a new waste heat boiler, a new CEMS, and a new ammonia storage tank. The curve was applied to the boiler FCCU feed rates to estimate the PWVs of five SCRs at the refineri es are listed in Table F.3.

Table F. 3 - Comparison of Cost Estimates for SCRs with and without Markups
Manufacturer’s costs Feed AQMD's with 2 layers of catalysts Rate Estimates and 2 levels of markups (10 3 Barrels PWV PWV = 2.8013*(Feed Rate ) 0.6

per Day) ($M) ($M) Ref 5 71 33 36 Ref 6 90 57 42 Ref 7 55 27 31 Ref 4 34 16 23 Ref 9 55 19 31 Total 152 163

### 141 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Summary of NEC’s Approach NEC based their estimation of PWV on a manufacturer’s detailed cost profile for a 3-bed SCR for Refinery 9 where 2 layers were designated for catalyst loading. NEC’s preferred engineering design required 3 catalyst layers (4-bed design with on bed in reserve) to meet the 2 ppmv emissions level. As such, the manufacturers design was scaled upw ard based on additional catalyst volume and associated costs as well as adjustments to the space velocity. The revised design was then subjected to the same cost assumptions st ated in staff approach #2. PWV was estimated for the several feed rates to establish a distribution that was the basis for a power law cost curve. (See Addendum-1 to the staff report for NEC’s analysis). During the review of the NEC report, it was noted that the initial feed rates used by NEC in estimating PWV were not consistent with reported levels (Table F.4).
Table F. 4 - Refinery Feed Rates of FCCUs in SCAQMD
Refinery No. 4 7 9 5 6 Back-calculated feed rates used by NEC, 10 3 Barrels/Day 58 68 60 79 79 Feed rates reported in SOx RECLAIM, 10 3 Barrels/Day 30 55 55 71 90 Feed rates shown in the Jan 22 14 Working Group Meeting, 34 49 52 67 84 10 3 Barrels/Day

x The NEC 3-layer SCR model PWV estimates were recalculated using the reported feed rates and the revised PWVs were reduced by 26% to reflect the difference between the NEC cost curve estimate for Refinery 1 and the PWV dete rmined by staff in Approach #1 above using the reported data.

x A comparison of the revised NEC cumulative PWVs adjusted by the 26 percent factor (2 vs. 3 catalyst layers for Refinery-1) with the staff approach #1 methodology were in good agreement (Table F.5).

### 142 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table F.5 – Estimates of Costs Adjusted to Refinery Feed Rates and Using the Refinery 1 26 Percent PWV Adjustment

Ref 5 Feed Rate (10 3 Barrels/D) 71 Staff’s Estimates ($M)

33 Revised NEC Estimates ($M)

34 Ratio Revised NEC/Staff’s

Estimates 1.03 Ref 6 90 57 40 0.70 Ref 7 55 27 29 1.07 Ref 4 34 16 22 1.38 Ref 9 55 19 29 1.53 Total 152 154 1.01

Summary of the Analysis Staff based its cost estimates on the application of a 2-catalyst layer SCR design for each of the refineries. The analysis focused on Refinery 1 which had achieved in practice an emissions level of 2 ppmv with the 2-catalyst layer design. NEC recommended a more conservative 3-catalyst layer design based upon their experience with refinery controls installations. Both designs have nearly equivalent estimated PWV when the 3-to-2 catalyst layer assumption is normalized. The costs estimated by staff provide a CE rangebetween $18K and $20 K per ton of NOx reduced. Using the NEC 3-Layer approach, the upper value of CE would be $29K.

### 143 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix G - Comparative Anal yses for Boilers & Heaters
This appendix provides a comparison of the control equipment designconfiguration, total installed cost (TIC) calculation and present worth Value (PWV) estimation used in the staff and NEC estimations for the boiler and heater cost eff ectiveness calculation. Table G.1 summarizes the basic comparison. Variations in the selective catalytic reduction (S CR) size, cost assumptions and TIC and PWV estimation methodology are provided in a side by side comparison for evaluation. As previously stated in Appendix B, the NEC desi gn to reach 2 ppmv relies on the use of 3 layers of catalyst and 1 additional layer for an Ammonia Slip Catalyst (ASC) bed. Staff’s estimate is based on existing SCR applications achieved-in-practice and alternate control methodologies identified in the analysis. Table G.1 - Comparison of Staff and NEC Control Equipment Designs, TIC and PWV Estimation Methods Staff's Design NEC's Design SCR Configuration 1-Catalyst layers 3-Catalyst layers 1-ammonia bed 4-Beds: all used Alternate Configurations Great Southern Flameless Heaters ClearSign Duplex burners
Cost Models Refinery survey data, refinery consultant’s data, cost estimates from SCR manufactures, Great Southern and ClearSIgn were used to construct maximum PWV of SCRs for 5 ppmv NOx for 5 ranges of boiler/heater firing rates. SCR Vendor Based application (scaled for 4- layers) with NEC modifications and refinery input. Additional cost for induced draft fan
CPWV of SCRs for 2 ppmv NOx = 1.1 * PWV of SCRs for 2 ppmv emissions limit for 5 ranges of boiler/heater firing rates Individual PWV Costs curves for 5 ppmv and 2 ppmv emissions limits based on maximum firing rate Refinery Application  8QLWV  7RQ  8QLWV  7RQ

Summary of Staff’s Approach

x Cost data for all feasible control technologies including SCRs, LoTOx, Great Southern flameless heaters, and ClearSign duplex burners was analyzed.

x Three sets of cost data were used to construct the cost curve in Figure G.1:

o Group 1 data set: Survey cost data provided directly bythe refineries for SCRs that achieved 1.6 – 3.5 ppmv NOx was use d. The refineries provided actual equipment costs, total installed cost s (TIC) and annual operating costs. The

### 144 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

actual costs were increased to 2014 dollars. From this set of actual costs: TIC = 3.87 x equipment costs, and PWV = 1.052 x TIC = 4.07 x equipment costs.

o Group 2 data set: Cost data estimated by the consultants for a refinery for future SCR projects was used. The consultants of the refinery applied a factor of 4.0 to estimate TICs for future projects (i.e . TIC = 4.0 x equipment costs), and staff estimated the PWVs consistently with th e actual cost data in Group 1, PWV = 1.052 x TIC.

o Group 3 data set: Equipment cost s provided by control equipment manufacturers for SCRs, Great Southern Flameless heaters, and ClearSign Duplex burners were used. TICs were estimated using a factor of 4.0, and PWVs were estimated using a factor derived from the Group 1 data set.

x Staff selected the upperbound PWVs shown in Figure G.1 for the costs of control devices that can achieve 5 ppmv NOx. Staff added another 10% to the upperbound costs in Figure 1 to derive the costs for control devices that can meet 2 ppmv NOx: 0IRUXQLWVZLWKPD[LPXPUDWLQJPP%WXKU $11 M for units with maximum rating > 100 – 200 mmBtu/hr $22 M for units with maximum rating > 200 – 400 mmBtu/hr $33 M for units with maximum rating > 400 – 600 mmBtu/hr $49.5 M for units with maximum rating > 600 mmBtu/hr
The upperbound PWVs derived were higher than all of the actual costs from the Group 1, 2 and 3 data sets. For example, the actual re ported costs for a 650 mmBtu/hr heater was about $42 M and the upperbound PWV that staff deri ved based on this approach was $49.5 M.
Summary of NEC’s Approach NEC concurred that the 2 ppmv BARCT level is feasible for refinery boilers/heaters >40 mmBtu/hr. However, NEC stated their recommendation required using SCRs with 4 layers of catalysts [3-layers plus 1-layer of ammonia slip catalyst (ASC)].

x NEC used the approach described in Appendi x F whereby a manufacturers design and quote for a 2-catalyst layer SCR (with 1-additional bed) was structured to accommodate a 4-layer SCR with 3-catalyst layers and an ammonium slip catalyst layer. Their estimate also included costs for a new CEMS, ammonia systemand induced draf t fan installation.

### 145 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

x NEC adjusted the manufacturer’s design to 10 ft/sec velocity, increased the cross section area, added a 3rd and a 4th layer of catalysts, increas ed the SCR dimension to 20 feet width x 19.2 feet length x 44 feet height, and increased the equipment costs to $2.48 M.
NEC estimated annual costs for ammonia usage, utility, catalyst replacement, and miscellaneous maintenance and developed 2 sets of PWV cost curves based on applying the NEC SCR model to a range of firing rates. The PWVs were estimated by NEC as follows: PWV = 3.1354 x (Maximum rating of boiler or heater) 0.3947 for 5 ppmv SCRs PWV = 3.4838 x (Maximum rating of boiler or heater) 0.3947 for 2 ppmv SCRs. NEC provided two curves for 2 ppmv SCR and 5 ppmv SCR that staff could use to estimate the incremental costs for boilers/heaters >110 mmBtu/ hr. Figure B.3 is revised below (Figure G.1) to include the NEC cost curves. The difference in the cost curve PWV project is most pronounced for the smaller units with maximum firing rates 200 mmBtu or less. As the firing rate increases beyond 500 mmBtu, the curves begin to converge.

Figure G. 1 - Present Worth Values for SCRs (December 2014)

### 146 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Summary and Discussion
The two methodologies employed to develop the PW Vs for SCRs are inherently different. The resulting number of units determined to be co st effective at 2 ppmv NOx at an under $50,000 per ton threshold varied from 48 using the NEC method to 103 units using the staff method. Using the NEC method resulted in 0.33 TPD less NOx reductions. As is noted in the following discussion, SCRs have ach ieved-in-practice 2 ppmv NOx in the Basin using the 1-catalyst layer SCR model. As a consequence of the uncertainty in PWV between the use of the two cost methodologies and CE estimation, staff is pr oposing to reduce the overall RECLAIM RTC reductions by the 0.33 TPD as a component of the overall adjustment from 14.8 to the 14.0 TPD proposal.
There are several heaters in the SCAQMD that have SCRs built to achieve 5 pppmv NOx, and these SCRs actually achieved 1.6 ppmv – 2.7 ppmv as reported by the refineries. All of these SCRs have 1 layer of catalysts. The catalyst depth is about 2 – 3 feet, and the catalyst volumes range from 62 – 623 cubic feet as shown in Tabl e G-2. By comparison, the Refinery 1 FCCU SCR has 2 layers of catalyst with a total catalyst dept h of 9 feet. The dimensions of the Refinery 1 FCCU SCR listed in Table G.2 are compared to the dimensions of the existing SCRs for refinery heaters. Refinery heater SCRs are more compact with smaller volumes of catalysts compared to FCCU SCRs. In contrast, Refinery 1 FCCU’s feed rate is about 95,000 barrels per day (B/D) yet Refinery 1 FCCU SCR achieved less than 2 ppmv NOx using only 2-catalyst layers.

### 147 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table G. 1 – Performance Levels and Dimens ions of Existing SCRs for Heaters in SCAQMD Compared to Existing SCR for an FCCU

Ref 9 3 hydro treating heaters Ref 5 isomax heater Ref 5 crude heater Ref 9 crude heater Ref 5 3 coker heaters Ref 5 4 ref

ormers Ref 1 FCCU

Maximum rating, mmbtu/hr 63 78 83 85 528 589 95,000 B/D
1.6 < 2ppmv
5 NOx, survey, ppmv 2.7 2.3 2.7 3.3 2.7 NOx, permit limit, ppmv n/a 5 5 5 n/a SCR, Width, ft 5 20 4 17 18 13 30 16 29 3 49 note 1, 2 41,748 SCR, Length, ft 6 7 6 7 18 SCR, Height, ft 4 6 3 12 20 Total SCR volume, ft3 110 798 note 1 1,380 6,300 Existing catalyst volume, ft3 92 92 62 96 623 537 6,210
1 2 (1 spare) 3 4.5 No of catalyst layers 1 1 1 1 1 Catalyst depth, ft 3 2 3 2 2 Note: 1) The SCR height s tated in the permit is likely for the catals yts and not for the overall SCR . 2) Dis trict recently approved a change of catalys ts for this SCR. New catalys t volume is 424 ft3, guarantee of <=5 ppmv NOx

### 148 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix H - Comparative Analyses for SRU/TGUs
This appendix provides a comparison of the pro posed control equipment design configuration, total installed cost (TIC) calculation and presen t worth Value (PWV) estimation used in the staff and NEC estimations for the SRU/TGTU cost effe ctiveness calculation. Table H.1 summarizes the basic comparison. Staff evaluated selective cat alytic reduction (SCR), LoTOx, and Know-NOx technologies while NEC expressed concerns on th e effectiveness and applicability of technologies other than SCR. Where comparable, variations in the SCR size, cost assumptions and TIC and PWV estimation methodology are provide in a side by side comparison for evaluation.
Table H-1 - Comparison of Staff and NEC Control Equipment Designs, TIC and PWV Estimation Methods Staff's Design NEC's Design

SCR Configuration 1-Catalyst layer 2 3-Catalyst layers 3-Beds: all used
Alternate Configurations LoTOx ozone injection coupled with either a Belco EDV or DynaWave scrubber Know-NOx ClO2 injection coupled with a DynaWave scrubber N/A

N/A
Additional Equipment Heat Exchanger Waste heat boiler (heat exchanger)
Cost Models Cost estimates: SCR manufacturers LoTOx and Know-NOx PWV estimated using EPA format (1.86 TIC) with 1.5 contingency factor

Costs revised to reflect NEC PWV 4.5 factor SCR Vendor Based application (scaled for 3- layers) with NEC modifications and refinery input.

Refinery Application  8QLWV  7RQ  8QLWV   /Ton

Summary of Staff’s Approach

x Cost data for all feasible control technologies including S CR, LoTOx, and KnowNOx were analyzed. SCR and LoTOx are used in refinery ap plications such as boilers, heaters, and FCCU while KnowNOx currently does not yet have any refinery application.

x Process information for three representative scenarios was sent to 2 SCR manufacturers, MECS (LoTOx), and KnowNOx. Cost data provided by the manufacturers using the EPA

### 149 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 OAQPS Guideline methodology were used to estimatethe TIC. This approach was used in the 2005 RECLAIM rule amendment. Instrumental = 10% x Equipment costs Sales Tax = 9% x Equipment costs Freight = 5% x Equipment costs Total Equipment Costs = 1.24 x Equipment costs Installation = 50% x Total Equipment Costs Total Installation Costs = ( 1.5) x Total Equipment Costs = 1.5 x 1.24 x Equipment Costs = 1.86 x Equipment Costs

x The SCR manufacturers also pr ovided other pertinent information such as the SCR overall dimension and the number of catalyst layers needed to achieve 2 ppmv for a SRU/TG incinerator application.

x A contingency factor of 1.5 was used to c over any uncertainty in the estimated costs.
Summary of NEC’s Approach As previously described in Appendix F, NEC based their estimation of PWV on a manufacturer’s detailed cost profile for a 3-bed SCR where 2 layers were designated for catalyst loading. NEC’s preferred engineering design required 3 catalyst laye rs (4-bed design with one bed in reserve) to meet the 2 ppmv emissions level. As such, the manufacturr’smanufacturer’s design was scaled upward based on additional catalyst volume and associated costs as well as adjustments to the space velocity. The revised design was then subjected to the cost assumptions stated in staff approach #2. PWV was estimated for the several feed rates to estab lish a distribution that was the basis for a power law cost curve. (See Adde ndum-1 to the staff report for NEC’s analysis).
Summary The staff and NEC approach to estimate the control costs differ. Addendum-1 of the Staff Report provides NEC’s non-confidential “SCAQMD NOx RECLAIM – BARCT Feasibility and Analysis Review”. A major difference between the two as sessments revolves around th e selection of control equipment analyzed. The SCAQMD analysis in cluded multiple control technologies while NEC analysis relied solely on SCR implementation wher e design options and costs were prorated for the SRU/TG applications. Additionally, costs as sociated with CEMS, ammonia storage tanks and heat exchangers account for differences between the initial staff and NEC cost estimates. Note that the different approaches do not have an impact on the list of equipment that meet the $50,000 per ton cost effectiveness thres hold for inclusion in the calculation of potential BARCT emission reductions from SRU/TGUs.

### 150 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

A second major difference between the two assessm ents occurs in the costing methodology to estimate TIC and PWV. Staff’s use of the EPA methodology with a 1.5 contingency factor markup to estimate PWV is lower than the combined bid conditioning, labor adjustment and 4.5 installation mark-up used by NEC. (It is important to note th at separate discussions with refiners and their consultants indicated that a mark-up factor of 4.0 or greater may be more representative). As stated in Appendix E, in their final assessment, staff revised its cost estimate to reflect the higher TIC to PWV cost factor proposed by NE C which resulted in closing the gap between the two analyses.

### 151 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix I - Comparative Anal yses for Coke Calciners
This appendix provides a comparison of the NOx emissions control designconfiguration, total installed cost (TIC) calculation and present worth Value (PWV) estimation used in the staff and NEC estimations for the Coke Calciner cost effe ctiveness calculation. Table I.1 summarizes the basic comparison. Variations in the equipment design, cost assumptions and TIC and PWV estimation methodology are provided in a sideby side comparison for evaluation.
Table I.1 Comparison of Staff and NEC Control Equipment Designs, TIC and PWV Estimation Methods Staff's Design NEC's Design

Proposed Control LoTOx or UltraCat LoTOx with modifications: taller or larger diameter scrubber, two vessels to enhance dry time, additional ozone usage and multiple ozone injection points Target Emissions Limit 2 ppmv 5- 10 ppmv

Cost Basis LoTOx TIC and UltraCat equipment costs provided by manufacturers LoTOx equipment costs provided by manufacturers LoTOX PWV calculated by multiplying a 1.5 contingency factor to TIC and annual operating costs. UltraCat TIC estimated using the U.S. EPA 1.86 factor. PWA calculated by multiplying a 1.5 contingency factor to TIC and annual operating costs TIC estimated as 1.35 factor applied to equipment cost to account for NEC proposed modifications. PWV calculated by multiplying a 3.44 contingency factor to TIC and annual operating costs

Summary of Staff’s Approach In order to collect cost data for all feasible control technologies, including LoTOx and UltraCat systems, staff sent the process information to the manufacturers, and the manufacturers provided equipment costs, annual operating costs, and foot print of the control devices. Staff used the approach in the EPA OAQPS Guidelines to es timate the Total Installed Costs (TIC = 1.86 x Equipment Costs.) This approach was used in the staff report of the 2005 RECLAIM rule amendment. Costs were increased by 50% to cover any uncertainty in the estimated TIC and annual operating costs.
Summary of NEC’s Approach NEC proposed 5 to 10 ppmv for BARCT. NEC usedthe costs provided to staff, and applied a factor of 4.67 to cover uncertainty in process deve lopment and installation costs. As a result, TIC = 4.67 x Equipment costs. Ultra-Cat was not c onsidered a solution for the coke calciner.
Summary

### 152 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Staff agrees that the coke calciner is a challeng ing application, and the BARCT level should be set at 10 ppmv as recommended by NEC. Addendum -1 of the Staff Report provides NEC’s nonconfidential “SCAQMD NOx RECLAIM – BARCT Feasibility and Analysis Review”. Staff also agrees that a factor higher than the EPA OAQPS’ s factor of 1.86 would be reasonable for the coke calciner because of the space congestion situation at the site. Staff revised the calculation and used a factor of 4.5 instead of 1.86 for both LoTOx and Ultra-Cat technologies.

### 153 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix J - Comparative An alyses for Turbine/Duct Burners

This appendix provides a comparison of the contro l design configuration, total installed cost (TIC) calculation and present worth Value (PWV) estimation used in the staff and NEC estimations for the Turbine/ Duct Burner cost effectiveness calculation. Table J.1 summarizes the basic comparison. The cost assumptions for TIC and PWV estimation methodology are provided solely for the staff proposal since NE C recommendation was to add catalyst to achieve the 2 ppmv targeted emissions limit.

### 154 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table J.1 - Comparison of Staff and NEC Control Equipment Designs, TIC and PWV Estimation Methods Staff's Design NEC's Design Control Devise Configuration Install new SCR with Ammonia Slip Catalysts and/or add catalyst to existing SCRs Add catalyst to existing SCRs

Cost Basis Cost information provide by several sources:
x SCR costs directly provided by Refineries 1 and 10;

x Costs also provided by vendor for SCR

x US EPA SCR cost estimate from literature

x Cheng Low NOx technology Costs information provided by vendor and Refinery 1

Cost Models Cost curve relating PWV to MW Cost curve relating PWV to MW

### 155 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix K – Co-Benefits of Energy Efficiency Projects

Table K.1 below summarizes NOx reductions that ar e expected to occur as co-benefits of energy efficiency projects undertaken by the refineries in the Basin from the California Air Resources Board (CARB)’s report “Energy Efficiency an d Co-Benefits Assessment of Large Industrial Sources – Refinery Sector Public Report, June 6, 2013. CARB approved the Energy Efficiency and Co-B enefit Assessment of Large Industrial Facilities (EEA Regulation) on July 22, 2010. The regulati on required the largest industrial sources in California to conduct a one -time assessment of fuel and ener gy consumption, and emissions of greenhouse gas, criteria pollutants, and toxic ai r contaminants. Affectedfacilities were also required to identify potential improvements in equipm ent, processes, or systems that could result in energy savings. http://www.arb.ca.gov/cc/energyaudits/energyaudits.htm#background

. CARB has a three-phase implementation plan to implement th e EEA Regulation. Phase 1 was to develop the industrial sector pub lic reports. From June 2013 to April 2015, CARB released five separate public reports compiling the information provided by the facilities subject to the EEA Regulation. The first report released in June 2013 was for the refinery sector. CARB is working on Phase 2 to develop the findings report, and Phase 3 to develop the Energy Efficiency Implementation Program. http://www.arb.ca.gov/cc/energyaudits/publicreports.htm

. CARB staff indicated that currently there was no requirement for the refineries to report the emissions stated in the public report released in June 2013 for inventory purposes. In addition, CARB had no process by which the inventory could be modified based on the estimates provided in the report. CARB did not know if the actua l emission reductions woul d be different from the estimates in the report, and CARB had no plan to count these estimate s as reductions to the current air quality. Thus, staff did not count the reductions in this proposal.

### 156 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table K. 1- Summary of Emission Reductions a nd Schedules of Energy Efficiency Projects

Facility Completed/Ongoing Projects Completed Before 2011 (tpd) Scheduled Projects After 2011 (tpd) Under Investigation Projects After 2011 (tpd) Total (tpd)

Range Completion Date Range Range
BP-Carson (Table II-4) 0.064 0.064 2009-11 0.014 0.019 0.019 0.097 0.097 Chevron El Segundo (Table II-9) 0. 054 0.088 2007-11 0 0 0 0.054 0.088 Phillips66 Carson (Table II-17) 0 0. 026 2008-11 0 0 0.013 0 0.039 Phillips66 Wilmington (Table II-21) 0 0 2009-11 0 0 0.013 0 0.013 ExxonMobil Torrance (Table II-29) 0.204 0.204 2008-11 0.036 0 0 0.24 0.24 Tesoro Los Angeles (Table II-37) 0.221 0.221 2009-11 0 0.049 0.049 0.27 0.27 Valero Wilmington (Table II-46) 0.056 0.056 2007-10 0 0 0 0.056 0.056 TOTAL (tpd) 0.6 0.7 0.1 0.1 0.1 0.7 0.8 Reference: Energy Efficiency and Co-Benefits Assessment of Large Industrial Sources - Refinery Sector Public Report, June 6, Note: BP Carson identified 21 projects completed in the 2009-11 time frame (p.35) Chevron identified 27 projects completed in the 2007-11 time frame (p. 38) Phillips66 Carson identified 8 projects completed in the 2008-11 time frame (p. 44) Phillips66 Wilmington identified 7 projects completed in the 2 009-11 time frame that reduced 0 tpd NOx (p. 47) ExxonMobil identified 25 projects completed in the 2008-2011 time frame (p.53) Tesoro identified 11 projects completed in 2009-11 time frame (p.59) Valero identified 13 projects completed in 2007-2010 time frame (p.65)

### 157 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix L – Survey Questionna ires for Refinery Sector
In June 2013, staff developed Survey Questionnaire to collect pertinent information for the NOx RECLAIM rule development. The Survey Questi onnaire was sent to the 37 top emitting facilities and California Portland Ce ment Company which was the #1 NOx emission source in the Basin in 2008. The Survey Questionnaire for the refinery sector and the non-refinery sector are shown below.
South Coast Air Quality Management 2013 NOx RECLAIM Survey Questionnaire for Refineries (Due Date: July 12, 2013)
Facility Contact 1. Please provide the facility contact for this project: Name: ________________________________ Title: ________________________________ Phone Number: _________________________ Email Address: _________________________
Top NOx Emitting Equipment or Processes (* The attached list may contain the information requested) 2. * Please verify the attached list for the top 10 NOx emitting equipment and processes at your facility in Compliance Year 2011 and their emissions. 3. Please mark on the attached list the NOx control equipment installed after the 2005 NOx RECLAIM amendment Boilers, Heaters, Furnaces, Kilns, Turbines, and Cogeneration Units (Major and Large Sources) 4. For each major and large combustion source at your facility, please verify the following information in the attached list, and provide in formation if the attached list does not contain this specific information: a. * Device description, Device ID, Process Name b. * Emissions in CY 2011 (tons per day) c. * Maximum unit rating (MMBTU/hr) d. * Type of fuel used e. Fuel usage rate and BTU content of fuel f. Flue gas flow rate (million dry standard cubic feet), temperature, oxygen and water content

### 158 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 g. Representative flue gas analysis and fuel gas analysis h. NOx concentration in the exhaust flue gas (ppmv at 3% O 2 or ppmv at 15% O 2 ). Please attach a copy of the most current source test reports/results. i. Allowable back pressure j. * Control technology used (e.g. LNB, SCR, NOx scrubber) 5. For the control technology identified in item #4 above: a. Device description, Device ID b. Manufacturer’s name and performance. Please attach a copy of manufacturer's specification/guarantee c. Design parameters (e.g. maximum flue gas flow rate, inlet and outlet ppmv, ammonia slip) d. If the control device is shared between multiple NOx emitting sources, please identify all other sources that are vented to this control device e. Dimension of the add-on NOx control device (e.g. length, width, height of the SCR, catalyst volume) f. Cost information (capital costs, insta llation costs, and annual operating costs) g. Installation date (e.g. July 2005) 6. Provide drawings that show location and distances between th e major and large NOx sources at the facility. Fluid Catalytic Cracking Units 7. If the facility currently uses NOx reduction catalysts, please provide: a. Manufacturer’s name b. Usage rate (e.g. lbs of catalysts added per day) c. Flue gas flow rate, temperature, oxyg en, water content and flue gas analysis d. NOx in the exhaust flue gas (ppmv at 3% O2). Please attach a copy of the source test results e. Cost information (annual operating costs) 8. If the facility uses add-on NOx control device, please provide: a. Manufacturer’s name and performance. Please attach a copy of manufacturer's specification/guarantee b. Design parameters (max flue gas flow rate, temperature, oxygen, water content, flue gas analysis) c. NOx in the exhaust flue gas (ppmv at 3% O2). Please attach a copy of the source test report/results d. Dimension of the add-on NOx control device e. Cost information (capital costs, inst allation costs, and annual operating costs) f. Installation date (e.g. July 2005) Reports Submitted Under the U.S. EPA Consent Decree

### 159 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 9. If the facility must install control technol ogy to reduce the NOx emissions under an U.S. Environmental Protection Agency (EPA)’s consen t decree, please provide the District a copy of the most recent reports/test results submitted to the EPA related to this consent decree. Feasible Control Approach Including Energy Efficiency Project 10. List any feasible control approach that your facility plans to install, including replacement of the existing units with higher energy efficient units, to further reduce your facility’s NOx emissions and green-house gase s. Provide a brief descrip tion of the control approach, manufacturer's name, estimated emissi on reductions, and cost information.

If you have any questions, please contact either: Minh Pham, P.E. (909) 396-2613, mpham@aqmd.gov , or

Gary Quinn, P.E. (909) 396-3121, gquinn@aqmd.gov
Please submit information via e-mail by July 12, 2013 to Minh Pham and Gary Quinn. Thank you for participating in the Survey.

### 160 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Part II – BARCT Analyses for Non-Refinery Sector
Part II contains the information related to the BARCT analyses for the non-refinery sector. Part II includes 7 Appendices from Appendix M to Appe ndix S that discuss 1) the NOx control technologies, 2) costs and cost effectiveness an alyses for the NOx emitting sources at the top 27 non-refinery facilities, and 3) staff’s review of the consultant’s costs and cost effectiveness analyses. The Survey Questionnaires for non-re finery facilities are included in Appendix T.

### 161 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015


## Appendix M – Cement Kilns
Process Description
In the NOx RECLAIM program there is one facility that operates cement kilns. This facility, under normal operation, has typically been among the hi ghest NOx emitters in the RECLAIM program. This facility produces gray cement from limestone, sand, shale, and clay raw materials. The raw materials are processed into a mix that is fed into a long, dry kiln that goes through pyroprocessing. Pyroprocessing transforms the fine raw mix into cement clinker through physical and chemical reactions inside the kiln. The facility operates two of these long, dry kilns that rotate slowly and are inclined at an angle. The raw materials are fed at the higher end of the kiln and proceed through it under the high heat of the combustion gases that are produced by the kiln burners at the lower end. Once the material exits the kiln, it is consid ered clinker and is cool ed, and further processed (ground, milled) into cement. The combustion fuels used in these kilns include petroleum coke, natural gas and tire-derived fuel (TDF). The fl ue gases exiting the kilns are then ducted to individual waste heat boilers that operate a steam generator for electricity. After the waste heat boilers, the flue gases from each kiln go to a dedicated baghouse which separates the solid particulate. The resultant flue ga ses then exit from individual stacks. In 2005, there was no new BARCT proposed for this source category. The emission factor has remained unchanged from the 2000 (Tier 1) Level, which is 2.73 pounds of NOx per ton of clinker produced. 

## Current Emission Inventory
There are two long, dry cement kilns located at the subject NOx RECLAIM facility. This facility was not in operation in compliance year 2011 due to decreased production and has not been in operation since. Therefore, for the purposes of calculating the BARCT reductions, the baseline emissions from the 2012 AQMP base year (2008) were used for the emission reduction determination and cost effectiveness calculation.

Table M. 1 - 2011 Emissions for Cement Kilns
Equipment Type (at Top 37 Facilities) Number of Units 2008 Emissions (tpd)
Long, Dry Cement Kiln 2 1.61

### 162 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015


## Control Technology
Long, dry cement kilns have achieved NOx reduc tions to the 2000 (Tier 1) level by utilizing low NOx burners and mid kiln firing with tire-derived fuel (TDF). With TDF, whole tires are introduced at an inlet location about midway alongthe kiln’s calcining zone. TDF lowers NOx emissions by lowering the flame temperatures and reducing thermal NOx with the introduction of a slower burning fuel. The facility began testing one of the kilns with a selective non-catalytic re duction system (SNCR) before it ceased operation. This approach involves in jecting ammonia directly into the kiln heating zone, where NOx reduction occurs without the utilization of a catalyst. With SNCR, the temperature window is critical for successful treatm ent of NOx. With a long, dry cement kiln, this is often difficult to achieve with the different te mperature zones along its length and the necessity to inject the reagent mid-kiln. NOx treatment is easier to achieve on more modern preheater/precalcining kilns with SNCR since they are often shorter in length and the temperature window lies towards the exit of the kiln at the lower part of the preheater tower. This allows for readily feasible reagent introduction. The testing of the SNCR system at the facility yielded about a 30% NOx reduction. As applied to other kilns, SNCR is capable of achieving between a 30 and 50% NOx reduction. In the case of this facility, a 45% NOx reduction would result in meeting the New Source Performance Standard (NSPS) level of 1.5 pounds of NOx per ton of clinker produced. This emission level is equivalent to th at of a new precalciner kiln using SNCR for NOx control.

After discussions with several ve ndors, there is more than one t echnology available for effective treatment of NOx from this source category beyond the Tier 1 level. To effectively achieve the most significant NOx reduction, sel ective catalytic reduction (SCR) is a proven technology that is well suited for the flue gas treatment of NOx. This technology uses a precious metal catalyst that selectively reduces NOx in the presence of ammonia. Ammonia is injected in the flue gas stream where it reacts with NOx and oxygen in the presence of the catalyst to produce nitrogen and water vapor. The typical operating temperature of the exhaust gas is between 450 and 850 degrees F. In cement applications, the inherently high particulate load of the flue gas stream has created problems in the past for catalysts. The dust can plug the catalyst matrix openings and can also mask active sites which results in a degradation of performance. This obstacle can be overcome by utilizing sootblowers which blow off the accumulated particulates at timed intervals from the catalyst surface. There have been several installations of SCR systems on cement kilns in Europe that can handle high dust loads in the flue gas. The installation at Monselice, Italy has been in operation since 2006 and the insta llation at Mergelstetten has b een in operation since 2010. An

### 163 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 SCR has also been installed on a long, dry kiln inJoppa, Illinois. It has been operating since 2013 and can achieve an 80% NOx reduction. For cement applications, an alternate technology is available primarily for multi-pollutant control. The system utilizes Ultra Cat ceramic fiber filters. The flue gas is injected with ammonia that mixes with the gas and permeates across the ceramic filter wall. The filter material is embedded with catalyst which removes the NOx. Dry sorbent is injected in the flue gas to react with SOx. The resultant particulate, along with other particulate matter is captured at the outside of the filter walls.

Figure M. 1 - Ultra Cat Ceramic Filter System The accumulated solids on the filters are removed by a pulsed jet of air through the filter and the resultant solid waste is collected underneath th e housing and is landfilled. This technology is guaranteed to achieve an 80% NOx reduction.

Figure M. 2 - Close-Up of Filter Housing and System Operation ( RefernceReference #2) Another multi-pollutant control option for cement kilns is also possible that would reduce SOx and PM with a wet gas scrubber and treat NOx with SCR. A wet gas scrubber uses a liquid

### 164 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 solution, typically caustic, as the absorbing agent for SO 2 . The absorbed SO 2 is converted to sulfates and sulfites which are then captured in the liquid effluent treatment system where they are separated and then disposed. So lid particulates in the flue ga s stream are removed by impaction with the liquid droplets inside the scrubber. The outlet flue gas stream is then processed by the SCR system for removal of NOx. Temperatur e control is extremely important for proper functioning of the pollutant control systems, primarily for SCR. The gas has to be hot enough after being processed by the scrubber for SCR treatment. This can be achieved by utilizing a heat exchanger ahead of the scrubber to reheat the gas to the proper temperature for SCR treatment. In this configuration, the scrubbing unit is installed ahead of the SCR for the purposes of removing SO 2 and preventing the formation of ammonium bisu lfate (ABS). ABS formation is a result of sulfur compounds reacting with ammonia from the SCR system at a lower temperature below the dew point. ABS formation is reversible, and this involves heating the catalyst to evaporate it. When SO 2 is present in the flue gas stream, the minimum SCR process temperature is determined by the formation of ABS. With the removal of SO 2 from the flue gas stream by the scrubber, however, ABS formation is not an issue when operating the SCR system at the lower end of the normal temperature range. 

## Proposed BARCT level and Emission Reductions
SCAQMD command and control Rule 1112 set NOx limits for gray cement kilns. Last amended in 1986, the rule limits NOx emissions to 6.4 pounds per ton of clinker produced, averaged over any 30 consecutive day period. The 2005 NOx RECLAIM amendment proposed no new BARCT for cement kilns, so these units have been only required to meet the Year 2000 Tier 1 emission level. The Tier 1 emission level for cement kilns is 2.73 pounds of NOx per ton of clinker produced. When they were in operation, the two units in the NOx RECLAIM universe of facilities were compliant with the Tier 1 NOx emission level. Based on vendor discussions, the proposed BARCTlevel for gray cement kilns is an 80% reduction and the control technology to achieve the NOx reductions is SCR or the Ultra Cat ceramic filter system. This would result in anemission level of about 0.5 pounds of NOx per ton of clinker produced.

The emission reductions achieved from the tw o long, dry cement kilns, based on the 2008 compliance year baseline emissions, amount to 1.2 9 tons per day. This is the incremental reduction from the Tier 1 emission level.

### 165 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015



## Cost Effectiveness
The total installed costs (TIC), which include equipment and installation costs were calculated by using vendor-supplied costs. For an SCR installation on both kilns, the equipm ent costs include the SCR equipment, ductwork, steel, electrical, ammoni a skid, sootblower air compressors, and insulation. The SCR system includes two layers of catalyst with a third layer for standby. A contingency value of 60% of the SCR equipment costs was estimated for the foundation civil work and other contingency. The SCR system for each kiln would be installed after the existing waste heat boiler and before the existing baghouse. This facility has specific plotspace considerations that would require the installation of the SCR system between 5 and 30 yards from each waste heat boiler, depending on the kiln. The equipment would be placed on elevated platforms to allow for vehicle and/or railcar traffic underneath. There is no expected heat loss from the insulated ductwork. The annual operating costs include ammonia consumption and catalyst replacement costs, which for this installation were assigned a three year replacement interval. For the Ultra Cat ceramic filter system, the equipment costs for both kilns include the emission control system, ammonia skid, booster fan, and engi neering services, along with the installation. The annual operating costs include ammonia consumption, dry sorbent consumption, power consumption, labor, waste disposal , replacement filter costs. Since this facility is also a SOx source, dry sorbent injection for SOx removal wi ll be required. This system would replace the existing baghouses at this facility. The vendor-based equipment costs for the wet scrubber with heat exchanger and SCR for each kiln include the costs for the heat exchanger systems (ductwork, housin g, dust collection hoppers), wet gas scrubber systems (venturi scrubber, pumps, stru ctural steel, piping), and the SCR systems (2 layers of catalyst for each kiln, ductwork, ammonia skid, programmable logic control, sootblowers). A contingency value of 60% of the equipment costs was estimated for the foundation and civil work, installation, and other contingency. The annual ope rating costs include ammonia consumption, catalyst replacement (3 year), caustic consumption, exhaust system fan power, scrubber pump power, and SCR dilution air fan and sootblower power. This system would replace the existing baghouses at this facility.

### 166 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 For all the scenarios, a present worth value (PWV) was calculated for the cement kilns using the TIC and annual costs (AC), and as sumes a 4% interest rate and a 25-year equipment life per the equation below. PWV = TIC + (15.622 x AC)

A cost effectiveness value was then calculated for each case scenario using the present worth value and dividing by the incremental emission reductions (ER, in tons per day) from the Tier 1 level over the control equipment life (25 years). This approach in calculating cost effectiveness utilizes the Discounted Cash Flow method (DCF). Cost Effectiveness = PWV / (ER x 365 x 25 years) Conversion to a Levelized Cash Flow (LCF) requi res a calculation using the following equation:
LCF Cost Effectiveness = (TIC x CRF) + AC / (ER x 365), where CRF is the Capital Recovery Factor assuming a 4% interest rate over an equipment life of 25 years.

Table M. 2 - Cost Effectiveness for Cement Kilns

Vendor 1: SCR system installed between wa ste heat boiler and baghouse. NOx removal only. Vendor 2: Dry scrubbing and ceramic filter system in stalled after the wa ste heat boiler and replacing the baghouse. NOx, SOx, and PM removal. Vendor 3: Wet gas scrubber and SCR system with heat exchanger installed after the waste heat boiler and replacing the baghouse. NOx, SOx, and PM removal. Vendor 1 Vendor 2 Vendor 3 Capital Costs ($) 14,950,000 30,000,000 31,938,838 Annual Costs ($) 1,220,500 1,000,000 4,818,537 Present Worth Value ($) 34,016,651 45,622,000 107,214,017 Emission reductions (tpd) 1.287 1.287 1.287 DCF Cost Effectiveness ($/ton) 2,897 3,885 9,130 LCF Cost Effectiveness ($/ton) 4,635 6,216 14,609
To achieve an 80% NOx reduction, the cost e ffectiveness for cement kilns ranges from $2,900/ton to $9,100/ton ($4,600/ton to $14,600/ton, using LCF). Since the facility is also a SOx source, the calculated cost effectiveness combining NOx and SOx reductions equates to $3,300/ton for Vendor 2 and $7,600/ton for Vendor 3. This assumes a SOx reduction of 0.25 tons per day, as stated for

### 167 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 the SOx RECLAIM amendment of 2010. All of the scenarios using the aforementioned NOx reduction technologies for flue gas treatment of cement kilns are considered cost effective. 

## Review of ETS’s Analysis for Cement Kilns
ETS, Inc. was commissioned by SCAQMD staff to provide an independent evaluation of the previously described BARCT and cost analysis. ETS conducted a site visit at the facility to verify site specific considerations for the installation of control equipment. For all the vendor installation estimates, a project scope contingency of 15% was applied to the total direct and indirect capital costs. ETS concurs that there is sufficient plot space to install the control equipment for all three vendors and that an 80% NOx emission reduction is both feasible and cost effective.

Table M. 3 - ETS Revisions to Cost Effectiveness for Cement Kilns

Vendor 1 : SCR system installed between waste heat boiler and baghouse. NOx removal only. Vendor 2 : Dry scrubbing and ceramic filter system installed after the waste heat boiler and replacing the baghouse. NOx, SOx, and PM removal. Vendor 3 : Wet gas scrubber and SCR system with heat exchanger installed after the waste heat boiler and replacing the baghouse. NOx, SOx, and PM removal. Vendor 1 Vendor 2 Vendor 3 Staff’s Estimate (ETS’s Estimate) Staff’s Estimate (ETS’s Estimate) Staff’s Estimate (ETS’s Estimate) Capital Costs ($) 14,950,000 (17,192,500) 30,000,000 (34,500,000) 31,938,838 (36,729,664) Annual Costs ($)* 1,220,500 1,000,000 4,818,537 Present Worth Value ($) 34,016,651 (36,259,151) 45,622,000 (50,122,000) 107,214,017 (112,004,843) Emission reductions (tpd) 1.287 1.287 1.287 DCF Cost Effectiveness ($/ton) 2,897 (3,088) 3,885 (4,268) 9,130 (9,538) LCF Cost Effectiveness ($/ton) 4,635 (4,941) 6,216 (6,829) 14,609 (15,262) * No revisions made by ETS The facility made several comments regarding th e BARCT analysis and staff conducted further research that resulted in a refinement of the cost analysis. Further communications with Vendor 1 revealed that the original estimate capital cost s should have been doubled, as the previous costs were clarified as being for only one kiln. The facility had a concern over the temperatures at the

### 168 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 exit of the waste heat boiler, before entering the control equipment. The facility provided an updated temperature which was 100 degrees below what had been provided previously and was below the normal operating temperature for norma l SCR operation. To address this change, additional costs for reheating the flue gas were incorporated into the estimate, along with the natural gas costs to fuel the added duct burner. This updated system would utilize a natural gasfired duct burner with a heat exchanger to reheatthe gas approximately 100-150 degrees to enable the SCR catalyst to operate normally. The project contingency and other contingencies were adjusted to reflect the updated costs. The capital and operational costs for reheating the flue gas were applied to all thre e vendor estimates. In ad dition, operational costs were incorporated into the Vendor 3 estimate for wastewater treatment of the wet gas scrubber effluent. Furthermore, costs for powering new induced draft (ID) fans werealso incorporated into the vendor estimates. Table M. 4 - SCAQMD Revisions to Cost Effectiveness for Cement Kilns

Vendor 1 : SCR system installed between waste heat boiler and baghouse. NOx removal only. Vendor 2 : Dry scrubbing and ceramic filter system installed after the waste heat boiler and replacing the baghouse. NOx, SOx, and PM removal. Vendor 3 : Wet gas scrubber and SCR system with heat exchanger installed after the waste heat boiler and replacing the baghouse. NOx, SOx, and PM removal. Vendor 1 Vendor 2 Vendor 3 ETS’s Estimate (Staff’s Estimate) ETS’s Estimate (Staff’s Estimate) ETS’s Estimate (Staff’s Estimate) Capital Costs ($) 17,192,500 (37,812,000) 34,500,000 (38,400,000) 36,729,664 (42,166,606) Annual Costs ($)* 1,220,500 (2,029,048) 1,000,000 (1,430,116) 4,818,537 (5,722,253) Present Worth Value ($) 36,259,151 (69,509,788) 50,122,000 (60,741,272) 112,004,843 (151,559,636) Emission reductions (tpd) 1.287 1.287 1.287 DCF Cost Effectiveness ($/ton) 3,088 (5,919) 4,268 (5,172) 9,538 (11,203) LCF Cost Effectiveness ($/ton) 4,941 (9,471) 6,829 (8,276) 15,262 (17,927) To achieve the proposed BARCT level, the revised cost effectiveness for cement kilns ranges from $5,200/ton to $11,200/ton ($8,300/ton to $17,900/ton, using LCF). All of these scenarios using the aforementioned NOx reduction technologies fo r flue gas treatment of cement kilns are considered feasible and cost effective.

### 169 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## References for Cement Kilns

1. Staff Report of Proposed Amendments to SOx RECLAIM. Agenda item 37 of the SCAQMD Governing Board Meeting. November 5, 2010.
2. World’s Largest Supplier of Cera mic Catalyst Filter Systems . Tri-Mer Corporation Brochure, 2015; www.tri-mer.com

. 3. Ammonium Bisulphate Inhibition of SCR Catalysts . Thogersen, J.; Slabiak, T.; White, N. Haldor Topsoe.
4. NOx RECLAIM BARCT Independent Evaluation of Cost Analysis Performed by SCAQMD Staff for BARCT in the Non-Refinery Sector . SCAQMD Contract #15343. ETS, Inc.; 2014.
5. The Costs and Benefits of Selec tive Catalytic Reduction on Ceme nt Kilns for Multi-Pollutant Control. Armendariz, A. Department of Environm ental and Civil Engineering, Southern Methodist University. February 11, 2008.
6. Elex CemCat’s SCR Technology . Elex Cemcat AG Presentation, March 2014; www.elexcemcat.com/news_en/

. 7. Evaluation of NOx Control Options for CalPortland’s Colton, CA Cement Kilns . Schreiber, R.; Russell, C. Schreiber Yonley & Associates, July 2, 2013.
8. Arizona Regional Haze and Interstate Visibility Transport Federal Implementation Plan, Final Rule . United States Environmental Protection Ag ency, Region 9. October 3, 2014; EPA-R09- OAR-2013-0588-0072.
9. EPA Air Pollution Control Cost Manual . United States Environmental Protection Agency. Office of Air Quality Planning a nd Standards. 2002; EPA/452/B-02-001.

### 170 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix N – Container Glass Melting Furnaces
Process Description
In the NOx RECLAIM program there is one facility among the top 37 NOx emitting facilities that operates container glass melting furnaces. This facility produces container glass from dry, solid raw materials that are melted in the furnaces and then formed into glass container bottles. In 2005, there was no new BARCT proposed for this source category. The emission factor has remained unchanged since 2000 (Tier 1), which is 1.2 pounds of NOx per ton of glass pulled. 

## Current Emission Inventory
There are two glass melting furnaces located at the subject NOx RECLAIM facility.

Table N. 1 - 2011 Emissions for Co ntainer Glass Melting Furnaces
Equipment Type Number of Units 2011 Emissions (tpd) Glass Melting Furnace (Container Glass) 2 0.30


## Control Technology

Glass melting furnaces can achieve NOx reductions to the 2000 (Tier 1) level by utilizing oxy fuelfiring. With oxy fuel firing, pure oxygen is used as the combustion reactant instead of nitrogenladen ambient air. A higher temperature can be achieved for the batch melt based on the higher combustion efficiency in addition to achieving lower NOx emissions. There is more than one technology available fo r effective treatment of NOx from this source category. To effectively achieve a significant NOx reduction, selective catalytic reduction (SCR) is a proven technology that is well suited for the fl ue gas treatment of NOx. This technology uses a precious metal catalyst that selectively reduces NOx in the presence of ammonia. Ammonia is injected in the flue gas stream where it reacts with NOx and oxygen in the presence of the catalyst to produce nitrogen and water vapor. The typi cal operating temperature of the exhaust gas is between 450 and 850 degrees F.

### 171 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 For glass melting applications, an alternate technology is available that has been achieved in practice, primarily for multi-pollutant control. The system utilizes Ultra Cat ceramic fiber filters. Please refer to Appendix M for further details. Th is technology is guaranteed to achieve an 80% NOx reduction and has been installed or is under construction at 12 glass manufacturing locations worldwide. 

## Proposed BARCT level and Emission Reductions
SCAQMD command and control Rule 1117 set NOx limits for glass melting furnaces. Last amended in 1984, the rule limits NOx emissions to 4.0 pounds per ton of glass pulled, effective in 1992. The 2005 NOx RECLAIM amendment proposed no new BARCT for container glass melting furnaces, so these units have been only required to meet the Year 2000 Tier 1 emission level. The Tier 1 emission leve l for container glass melting furnaces is 1.2 pounds of NOx per ton of glass pulled. The two units in the NOx RECLAIM universe are currently compliant with the Tier 1 emission level. Based on vendor discussions, the proposed BARCT le vel for container glass melting furnaces is an 80% reduction and the control technology to ac hieve the NOx reductions is SCR or the Ultra Cat ceramic filter system. This would result in a NOx emissi on rate of 0.24 pounds per ton of glass pulled. The emission reductions achieved from the two container glass melting furnaces, based on the reported value of emissions, amount to 0.24 tons per day. This is the incremental reduction from the Tier 1 emission level of 1.2 pounds of NOx per ton of glass pulled.


## Cost Effectiveness
The total installed costs (TIC), which include equipment and installation costs were calculated by using vendor-supplied costs and the costs provided by the facility. For the Ultra Cat ceramic filter system, the equi pment costs were scaled from an existing vendorbased installation quotation for a sodium silicate glass melting fu rnace. The equipment costs which include the emission control system, ammonia skid, and booster fan were scaled by the heat input rate to the 0.6 power based on general che mical engineering cost estimating practice. The installation costs were calculated to be 40% of the equipment costs. The cost of installation as well as the cost of engineering services was s caled by the heat input rate. The annual operating costs (also scaled by heat input rate) includeammonia consumption, dry sorbent consumption, power consumption, labor, waste di sposal, replacement filter costs. Since this facility is also a SOx source, dry sorbent injection for SOx removal will be required. This system would replace the existing dry scrubbing system and electrostat ic precipitators (ESPs) at this facility.

### 172 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

For an SCR installation, two scenarios were consid ered. In the first scenario, one SCR chamber would handle the exhaust streams from the three ESPs. At this facility, three ESPs handle the exhaust from the two glass melting furnaces in wh ich one ESP is operated as a backup. In the second scenario, one SCR would handle the exhaus t from each ESP, so there would be a total of three SCR systems installed. The vendor-based costs for the first option incl ude the engineering, fabrication and field installation of a single SCR chamber sized to handle the exhaust from both furnaces. The SCR system includes one layer of catalyst with ex tra space for a second layer, supporting structure, ammonia skid, and programmable logic control (P LC) system. A contingency value of 80% of the SCR equipment costs was estimated for the foundation and ductwork to and from the existing stacks. This facility has specific plot space considerations that would require the installation of the SCR system roughly 30 yards from the ESPs and roughly 15 yards back to the stacks. The equipment would be placed on anelevated platform above the existing rail line. The annual operating costs include ammonia consumption and catalyst replacement costs, which for this installation were conservatively assigned an annual replacement interval. In addition, a 20% contingency was added to the annual costs for freight and installation. The vendor-based costs for the second option incl ude the engineering, fabrication and field installation of three SCR chambers as describe d for the first option, each sized to handle the exhaust from one furnace. A contingency value of 150% of the SCR equipment costs was estimated for the foundation and duc twork to and from the existing stacks. The annual operating costs were also derived as desc ribed for the first option. This option also included an additional 20% contingency. The facility also provided an estimate for the retrofitting of one furnace that was based on the EPA cost manual for SCR installations for NOx removal. To expand this singular case to address the remaining furnace, two scenarios were consider ed for this approach. The first option would include the installation of two SCR systems, eachsized to handle the exhaust of one furnace, manifolded to the existing three ESPs. The second option would include the installation of three SCR systems, each sized to handle the exhaust of one furnace. Each SCR would handle the exhaust from each ESP. For each option, the costs for additional SCRs were calculated by multiplying the facility-provided costs for a single unit with num ber of additional units required for each of the two options. Also for each option, a 15% contingency factor was applied to th e direct and indirect costs. The annual operating costs for eachoption include operati ons and maintenance labor/materials, ammonia consump tion, power consumptions and catalyst costs. In addition, an indirect annual cost factor was added and was calculated to be th e capital costs multiplied by the capital recovery factor (CRF) for a 25 year installation at a 4% interest rate.

### 173 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 For all the scenarios, a present worth value (PWV) was calculated for the glass melting furnaces using the TIC and annual costs (AC), and assumes a 4% interest rate and a 25-year equipment life per the equation below.
PWV = TIC + (15.622 x AC)

A cost effectiveness value was then calculated for each case scenario using the present worth value and dividing by the incremental emission reductions (ER, in tons per day) from the Tier 1 level over the control equipment life (25 years). This approach in calculating cost effectiveness utilizes the Discounted Cash Flow method (DCF). Cost Effectiveness = PWV / (ER x 365 x 25 years) Conversion to a Levelized Cash Flow (LCF) requi res a calculation using the following equation:
LCF Cost Effectiveness = (TIC x CRF) + AC / (ER x 365), where CRF is the Capital Recovery Factor assumin g a 4% interest rate over an equipment life of 25 years.
Table N. 2 - Cost Effectiveness for Container Glass Melting Furnaces

Vendor 1: Dry scrubbing and ceramic filter system installed after the furnaces, replacing the dry scrubber and ESP. NOx, SOx, and PM removal. Vendor 2: SCR system installed post ESP. NOx removal only. Option 1: single chamber. Option 2: three chambers. Vendor 3: SCR system installed post ESP using costs provided by facility per EPA cost Manual. NOx removal only. Option 1: two chambers. Option 2: three chambers. Vendor 1 Vendor 2 Option 1 Vendor 2 Option 2 Vendor 3 Option 1 Vendor 3 Option 2 Capital Costs ($) 5,134,891 2,070,000 5,000,000 4,096,959 6,145,439 Annual Costs ($) 567,686 132,500 180,750 560,123 840,185 Present Worth Value ($) 14,003,287 4,139,195 7,823,677 12,847,207 19,270,811
Emission reductions (tpd) 0.24 0.24 0.24 0.24 0.24
DCF Cost Effectiveness ($/ton) 6,442 1,904 3,599 5,910 8,865

LCF Cost Effectiveness ($/ton) 10,308 3,047 5,759 9,457 14,186

### 174 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

To achieve an 80% reduction, the cost effectiv eness for container glass melting furnace ranges from $1,900/ton to $8,900/ton ($3,000/ton to $14,200/ton, using LCF). All of these scenarios using the aforementioned NOx reduction technologie s for flue gas treatment of container glass melting furnaces are considered cost effective. 

## Review of ETS’s Analysis for Container Glass Melting Furnaces
ETS, Inc. was commissioned by SCAQMD staff to provide an independent evaluation of the previously described BARCT and cost analysis. ETS conducted a site visit at the facility to verify site specific considerations for the installation of control equipment.
For the Vendor 1 estimates, the calc ulation of the insta llation costs were adjusted to reflect 40% of the equipment costs, instead of being scaled from the base equipment case. Additionally, a contingency of 15% of the capital costs was applied to the overall estimate. The Vendor 2 estimates were also adjusted by ETS for several items. Foundation and ductwork costs were added, as well as costs for new st acks for both options (single and three SCRs). Operation and labor costs were adde d to the annual costs for both options as well as costs for power consumption with the addition of a booster fan. Th e annual catalyst replac ement costs were also adjusted for both options to reflect labor costs to replace the catalyst, along with recycling/disposal costs for spent catalyst. Additionally, a contingency of 15% of the capital costs was applied to the overall estimate. The Vendor 3 cost estimates were not evaluated by ETS because they felt that the cost estimates provided by the equipment vendors with actual field experience w ith NOx removal would provide better estimates than the EPA cost manual method. Also, there was a disparity in the costs with the vendor estimates versus the EPA cost manual method because economics of scale were not taken into consideration, such as volume cost savings for multiple pieces of equipment. Since the glass melting furnaces at this facility are also SOx emission sources, the flue gas has to be at a sufficiently high temperature to prevent ammonium bisulfate formation (ABS) while also removing NOx emissions effectively. ABS forms when the SO 3 in the flue gas reacts with the ammonia in the SCR system to produce ammonium salts. If the flue gas temperature is above the dew point for ABS, it will remain in the gaseous phase. However, if the temperature of the flue gas falls below the dew point for ABS, it will precipitate and deposit as a sticky substance on the SCR catalyst matrix. The result is reduced activity of the SCR catalyst and it will need to be reheated to reverse the process and reactivate it. Upon speaking with the equipment vendors, the SOx emissions from the glass melting furnaces woul d not result in ABS formation as long as the

### 175 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 flue gas temperature remains as high as possible, any heat loss from the ductwork is mitigated, and there is not an overly lengthy duct run constructed to the SCR. The current stack temperatures at the facility are adequately above the ABS dew poin t and, therefore, there is no foreseeable issue with ABS deposition on the SCR catalyst. ETS concurs that the NOx emission levels that are achievable is 80% for this source category. Achieving this level would be feasible with both technologies evaluated (i.e., ceramic filtration system or SCR). The plot considerations at this facility are complex, leaving little room for the installation of control equipment. The Vendor 1 system would involve removing the existing SOx dry scrubbers to create additional space and would need to be tied in presumably under a facility shutdown period. The Vendor 2 system would be co mplex as well, but ETS concurs that there is sufficient plot space for the installation of SCR. To achieve the proposed BARCT level, the revised cost effectiveness for container glass melting furnaces ranges from $3,000/ton to $8,900/ton ($4,700/ton to $14,200/ton, using LCF). All of these scenarios using the aforementioned NOx re duction technologies for flue gas treatment of container glass melting furnaces are consid ered feasible and cost effective.

### 176 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table N. 3 - ETS Revisions to Cost Effectiveness for Container Glass Melting Furnaces

Vendor 1: Dry scrubbing and ceramic filter system installed after the furnaces, replacing the dry scrubber and ESP. NOx, SOx, and PM removal. Vendor 2: SCR system installed post ESP. NOx removal only. Option 1: single chamber. Option 2: three chambers. Vendor 3: SCR system installed post ESP using costs provided by facility per EPA cost manual. NOx removal only. Option 1: two ch ambers. Option 2: three chambers. Vendor 1 Vendor 2 Option 1 Vendor 2 Option 2 Vendor 3 Option 1 Vendor 3 Option 2 Staff’s Estimate

(ETS’s Estimate) Staff’s Estimate

(ETS’s Estimate) Staff’s Estimate

(ETS’s Estimate) Staff’s Estimate* Staff’s Estimate*

Capital Costs ($) 5,134,891 (5,684,463) 2,070,000 (2,685,250) 5,000,000 (5,405,000) 4,096,959 6,145,439
Annual Costs ($) 567,686* 132,500 (240,909) 180,750 (360,753) 560,123 840,185
Present Worth Value ($) 14,003,287 (14,55 2 2,859) 4,139,195 (6,448,737) 7,823,677 (11,040,686) 12,847,207 19,270,811
Emission reductions (tpd) 0.24 0.24 0.24 0.24 0.24

DCF Cost Effectiveness ($/ton) 6,442 (6,695) 1,904 (2,967) 3,599 (5,079) 5,910 8,865

LCF Cost Effectiveness ($/ton) 10,308 (10,713) 3,047 (4,747) 5,759 (8,127) 9,457 14,186

*No revisions were made by ETS to the Vendor 3 costing or the indicated fields

### 177 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## References for Container Glass Melting Furnaces

1. Alternative Control Techniques Document – NOx Emissions from Glass Manufacturing. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards. June 1994; EPA-453/R-94-037. 2. Staff Report of Proposed Amendments to SOx RECLAIM. Agenda item 37 of the SCAQMD Governing Board Meeting. November 5, 2010.
3. World’s Largest Supplier of Cera mic Catalyst Filter Systems . Tri-Mer Corporation Brochure, 2015; www.tri-mer.com

. 4. Ammonium Bisulphate Inhibition of SCR Catalysts . Thogersen, J.; Slabiak, T.; White, N. Haldor Topsoe.
5. EPA Air Pollution Control Cost Manual . United States Environmental Protection Agency. Office of Air Quality Planning a nd Standards. 2002; EPA/452/B-02-001.
6. NOx RECLAIM BARCT Independent Evaluation of Cost Analysis Performed by SCAQMD Staff for BARCT in the Non-Refinery Sector . SCAQMD Contract #15343. ETS, Inc.; 2014.

### 178 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix O– Sodium Silicate Furnace
Process Description
In the NOx RECLAIM program there is only one f acility that produces sodium silicate. Sodium silicate is a substance either in a solid or liquid form that has a variety of industrial uses. It is manufactured by heating soda ash and sand in a me lting furnace. The materials react with heat to produce sodium silicate and carbon dioxide. In 2005, there was no new BARCT proposed for this source category. The emission factor has remained unchanged since 2000 (Tier 1), which is 6.4 pounds of NOx per ton of glass pulled. This unit is considered a glass melting furnace, but since it processes sodium silicate, it is different than other types of glass melting furnaces such as container glass, flat glass, etc. 

## Current Emission Inventory
The single source sodium silicate melting furnace is a NOx major source.

Table O. 1 - 2011 Emissions for Sodium Silicate Furnace
Equipment Type Number of Units 2011 Emissions (tpd) Sodium Silicate Furnace 1 0.11



## Control Technology
The raw material batch feed is delivered into the melting furnace which is fired by several natural gas-fired burners that melt the process feed. The flue gas then exits the furnace via a stack into the atmosphere. Combustion technology can often be employed to achieve some NOx reductions. Blower air staging, for example, can lower the temperature and result in lowering NOx emissions by around 15 to 20%. To effectively achieve the largest reduction, howev er, selective catalytic reduction (SCR) is the technology that is best suited for significant fluegas treatment of NOx. This technology uses a precious metal catalyst that selectively reduces NOx in the presence of ammonia. Ammonia is injected in the flue gas stream where it reacts with NOx and oxygen in the presence of the catalyst

### 179 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 to produce nitrogen and water vapor. The typi cal operating temperature of the exhaust gas is between 450 and 850 degrees F. For glass melting applications, an alternate technology is available that has been achieved in practice, primarily for multi-pollutant control. The system utilizes Ultra Cat ceramic fiber filters. Please refer to Appendix M for further descriptions. This technology is guaranteed to achieve an 80% NOx reduction. 

## Proposed BARCT level and Emission Reductions
In command and control, SCAQMD Rule 1117 set limits for glass melting furnaces. Last amended in 1984, the rule limits NOx emissions to 4.0 po unds per ton of glass pulled, effective in 1992. The 2005 NOx RECLAIM amendment proposed no ne w BARCT for sodium silicate furnaces or other glass melting furnaces, so these units have been only required to meet the Year 2000 Tier 1 emission level. The Tier 1 e mission level for sodium silicate furnaces is 6.4 pounds per ton of glass pulled. The single unit in the NOx RECLAIM universe is currently compliant with the Tier 1 emission level. For sodium silicate furnaces based on vendor discussions, the proposed BARCT level for this source category is an 80% reduction and the control technology to achieve the NOx reductions is SCR or the Ultra Cat ceramic filter system. The emission reductions achieved from the sodium silicate furnace, based on the reported value of emissions, amounts to 0.09 tons per day. This is the incremental reduction from the Tier 1 emission level and is almost equi valent to the Tier 1 emission level fo r container glass melting furnaces (1.2 lbs/ton of glass pulled).


## Cost Effectiveness
The total installed costs (TIC), which include equipment and installation costs were calculated by using vendor-supplied costs. There are no site -specific conditions that would increase the installation costs dramatically. For SCR, the equipment and installation costs incl ude the SCR chamber, one layer of catalyst with extra space for a second layer, supporting structur e, ammonia skid, programmable logic control system (PLC), and engineering/fabrication. The foundation and ductwork was estimated to be 60% of the equipment and installation costs. The annual operating costs include ammonia consumption and catalyst replacement costs, wh ich for this installation were conservatively

### 180 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 assigned an annual replacement interval. In a ddition, a 20% contingency was added to the annual costs for freight and installation. For the Ultra Cat ceramic filter system, the equipment costs include the emission control system, ammonia skid, booster fan, and engineering services. The installation costs were calculated to be 40% of the equipment costs. The annual ope rating costs include ammonia consumption, power consumption, labor, waste disposal and replacement filter costs. Since this facility is not a SOx source, dry sorbent injection for SO x removal would not be required. For both technologies, a present worth value (PWV) was calculated for the sodium silicate furnace using the TIC and annual costs (AC), and assumes a 4% interest rate and a 25-year equipment life per the equation below.
PWV = TIC + (15.622 x AC)

A cost effectiveness value was then calculated for each technology using the present worth value and dividing by the incremental emission reductions (ER, in tons per day) from the Tier 1 level over the control equipment life (25 years). This method of calculating cost effectiveness utilizes the Discounted Cash Flow method (DCF). Cost Effectiveness = PWV / (ER x 365 x 25 years) Conversion to a Levelized Cash Flow (LCF) requi res a calculation using the following equation:
LCF Cost Effectiveness = (TIC x CRF) + AC / (ER x 365), where CRF is the Capital Recovery Factor assumin g a 4% interest rate over an equipment life of 25 years.

Table O. 2 - Cost Effectiveness for Sodium Silicate Furnace

Control Technology TIC ($) AC ($) PWV ($) ER (tpd) DCF C.E. ($/ton) SCR 1,600,000 76,315 2,792,193 0.09 3,470 Ultra Cat 1,986,161 166,016 4,579,663 0.09 5,691

The cost effectiveness for the sodium sili cate furnace ranges from $3,500/ton to $5,700/ton ($5,600/ton to $9,100/ton, using LCF). This is to achieve an 80% NOx reduction. Both technologies for reducing NOx for the sodium silic ate furnace are consider ed cost effective.

### 181 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Review of ETS’s Analysis fo r Sodium Silicate Furnace
ETS, Inc. was commissioned by SCAQMD staff to provide an independent evaluation of the previously described BARCT and cost analysis . ETS conducted an evaluation of the control technology and the costs for the insta llation of the control equipment. For both vendor estimates, a contingency of 15% was applied the total directand indirect capital costs. For the Vendor 2 estimate, the capital costs pertinent to SO 2 treatment were removed since this system would be removing NOx only. To achieve the proposed BARCT level, the revise d cost effectiveness for the sodium silicate furnace ranges from $3,800/ton to $5,700/ton ($6,000/ton to $9,200/ton, using LCF). Both scenarios using the aforementioned NOx reduction technologies for flue gas treatment of the sodium silicate furnace are consider ed feasible and cost effective.

Table O. 3 - ETS Revisions to Cost Effectiveness for Sodium Silicate Furnace

Vendor 1: Dry scrubbing and ceramic filter system installed after the furnaces, replacing the dry scrubber and ESP. NOx, SOx, and PM removal. Vendor 2: SCR system installed post ESP. NOx removal only. Option 1: single chamber. Option 2: three chambers. Vendor 1 Vendor 2 Staff’s Estimate (ETS’s Estimate) Staff’s Estimate (ETS’s Estimate) Capital Costs ($) 1,600,000 (1,840,000) 1,986,161 (2,009,243) Annual Costs ($)* 76,315 166,016 Present Worth Value ($) 2,792,193 (3,032,193) 4,579,663 (4,602,745) Emission reductions (tpd) 0.09 0.09 DCF Cost Effectiveness ($/ton) 3,470 (3,768) 5,691 (5,719) LCF Cost Effectiveness ($/ton) 5,552 (6,029) 9,106 (9,152) *No revisions were made by ETS

### 182 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## References for Sodium Silicate Furnace

1. World’s Largest Supplier of Cera mic Catalyst Filter Systems . Tri-Mer Corporation Brochure, 2015; www.tri-mer.com

. 2. NOx RECLAIM BARCT Independent Evaluation of Cost Analysis Performed by SCAQMD Staff for BARCT in the Non-Refinery Sector . SCAQMD Contract #15343. ETS, Inc.; 2014.
3. EPA Air Pollution Control Cost Manual . United States Environmental Protection Agency. Office of Air Quality Planning a nd Standards. 2002; EPA/452/B-02-001.

### 183 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix P – Metal Heat Treating Furnaces >150 MMBTU/hr
Process Description
In the NOx RECLAIM program there is one fac ility that operates these furnaces among the top 37 facilities. For the 2005 NOx RECLAIM am endment, a BARCT level of 45 ppm (0.055 lb/MMBTU) was established for metal heat treating furnaces. 

## Current Emission Inventory
Among the top 37 facilities in the NOx RECLAIM program, there are two furnaces above 150 MMBTU/hr that are metal heat treating furnaces for processing steel.

Table P. 1 - 2011 Emissions for Metal He at Treating Furnaces >150 MMBTU/hr
Equipment Type (at Top 37 Facilities ) Number of Units 2011 Emissions (tpd) Furnace >150 MMBTU/hr 2 0.49 

## Control Technology
As with all combustion sources, the type of burne r used can affect the emissions. Some burners are lower NOx emitting than others. But for these types of furnaces, there are often dozens of burners that cumulatively require a high heat input . To achieve higher efficiency and to consume less fuel, recuperative and regenerative burners ar e used. These burners employ the principle of using preheated inlet air which is heated by the exhaust gases for more efficient combustion. To effectively achieve a significant NOx reduc tion, however, selective catalytic reduction (SCR) is the technology that is best suited for the flue gas treatment of NOx. This technology uses a precious metal catalyst that selectively reduces NOx in the presence of ammonia. Ammonia is injected in the flue gas stream where it reacts with NOx and oxygen in the presence of the catalyst to produce nitrogen and water vapor. The typi cal operating temperature of the exhaust gas is between 450 and 850 degrees F.

### 184 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Proposed BARCT level and Emission Reductions
In command and control, SCAQMD Rule 1147 set limits for metal heat treating furnaces at 60 ppm at 3% O 2 (0.073 lb/MMBTU). This rule was adoptedin 2008 to address NOx emissions from miscellaneous sources. The 2005 NOx RECLAI M amendment proposed a BARCT level of 45 ppm at 3% O 2 (0.055 lb/MMBTU).

Based on vendor discussions for furnaces above 150 MMBTU/hr, the proposed BARCT level for this source category is an 80% reduction and the control technology to achieve the NOx reductions is SCR. An 80% NOx reduction from the 2005 BARCT level is equivalent to 9 ppm at 3% O 2 . The 2011 emissions adjusted to the 2005 BARCT level amount to 0.70 tons per day. The incremental reductions from each furnace from the 2005 BARCT level to the proposed BARCT level are 0.28 tons per day. One of the furnaces is already operating with an SCR system and is currently achieving around 20 ppm NOx. The s ource category incremental emission reductions achieved from the metal heat treating furnac es above 150 MMBTU/hr from the 2005 BARCT level amount to 0.56 tons per day.


## Cost Effectiveness
The total installed costs (TIC), which include equipment and installation costs were calculated by using vendor-supplied costs and the costs from an existing installation. For SCR, the vendor-based equipment and installa tion costs include the SCR catalyst, reactor and ductwork, ammonia skid, dilution air fan, civil wo rk, and installation. A contingency value of 200% of the SCR equipment costs was used to estimate the installation, foundation, civil work, and other construction un certainties. The annual operating co sts include ammonia consumption, catalyst replacement costs (2 year replacement interval), power consumption, and maintenance. The existing equipment-based equipment costs in clude installation, SCR catalyst system, ammonia skid, and control system. A 60% contingency va lue of the equipment and installation cost was used to estimate the costs for other ductwork. The annual operating costs include ammonia consumption, catalyst replacement costs (2 year replacement interval), and maintenance. For both scenario cases, a present worth value (PWV) was calculated for the metal heat treating furnaces using the TIC and annual costs (AC), and assumes a 4% interest rate and a 25-year equipment life per the equation below.
PWV = TIC + (15.622 x AC)

### 185 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

A cost effectiveness value was then calculated for each case scenario using the present worth value and dividing by the incremental emission reductions (ER, in tons per day) from the Tier 1 level over the control equipment life (25 years). This method of calculating cost effectiveness utilizes the Discounted Cash Flow method (DCF). Cost Effectiveness = PWV / (ER x 365 x 25 years) Conversion to a Levelized Cash Flow (LCF) requi res a calculation using the following equation:
LCF Cost Effectiveness = (TIC x CRF) + AC / (ER x 365), where CRF is the Capital Recovery Factor assumin g a 4% interest rate over an equipment life of 25 years.

Table P. 2 - Cost Effectiveness for Furnaces > 150 MMBTU/hr

Control Technology TIC ($) AC ($) PWV ($) ER (tpd) DCF C.E. ($/ton) Vendor-based 2,800,152 440,631 9,683,684 0.28 3,800 Existingequipmentbased 3,732,800 255,600 7,725,783 0.28 3,000

The cost effectiveness for furnaces above 150 MMBTU/hr ranges from $3,000/ton to $3,800/ton ($4,800/ton to $6,100/ton, using LCF). Achieving an 80% NOx reduction, SCR technology applied for reducing NOx for these furnac es is considered cost effective. 

## Review of ETS’s Analysis for Meta l Heat Treating Furnaces >150 MMBTU/hr
ETS, Inc. was commissioned by SCAQMD staff to provide an independent evaluation of the previously described BARCT and cost analysis. Based on staff’s analysis and the review of technical information, ETS concurs that the NOx reduction level that can be achieved with SCR technology is 80%. No changes to the cost estimates were made.

### 186 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## References for Metal Heat Trea ting Furnaces >150 MMBTU/hr

1. EPA Air Pollution Control Cost Manual . United States Environmental Protection Agency. Office of Air Quality Planning a nd Standards. 2002; EPA/452/B-02-001.
2. NOx RECLAIM BARCT Independent Evaluation of Cost Analysis Performed by SCAQMD Staff for BARCT in the Non-Refinery Sector . SCAQMD Contract #15343. ETS, Inc.; 2014.

### 187 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix Q – Non-Refinery, Non-Electrical Electrcity Generating Facility S tationary Gas Turbines
Process Description
In the RECLAIM program, stationary gas turbines are used primarily to drive compressors or to generate power. In command and control, Rule1134 limits the NOx emissions for all gaseous and liquid-fueled engines that are above 0.3 MW. Ga s turbines operate either in simple cycle or combined cycle. Simple cycle units use the mechanic al energy of shaft work that is transferred to and used by a gas compressor, for example, or to run an electrical generator to produce electricity. A combined cycle unit adds an additional element of heat recovery from its exhaust gases to produce more power by way of a steam generator. Combined cycle units are more efficient due to their use of two work cycles from the same shaft operation. Gas turbines can operate on both gaseous and liquid fuels. Gaseous fuels include natu ral gas, process gas, and refinery gas. Liquid fuels typically include diesel. The units in this category are not electrical electricity generating facility turbines (turbines that produce solely el ectric utility power). Some of these units are cogenerating units that, in add ition to producing in-house power, also recover the useful energy from heat recovery for producing process steam. In 2005, there was no new BARCT proposed for this source category. The emission factor ha s remained unchanged since 2000 (Tier 1), which equates to 0.06 lb/MMBTU. 

## Current Emission Inventory
Among the top thirty seven non-el ectrical electricity generating f acility NOx emittin g facilities in the RECLAIM universe, there are twenty gas turbines that are either major or large source units. Four of these units are currently utilizing some level of NOx control with selective catalytic reduction (SCR). The OCS turbines, which are fire d on diesel or process gas, have the highest NOx emission concentrations in this source categ ory. Six of these units are operated on an offshore oil drilling platform (outer continental shelf, or OCS).

### 188 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Table Q. 1 - 2011 Emissions for RECLAIM Non- Electrical Electrcity Generating Facility Gas Turbines
Turbine Type Number of Units 2011 Emissions (tpd) Total 20 1.92 Gas Compression 7 0.59 Cogeneration 6 0.75 Power Generation 1 0.09 OCS 6 0.49



### ppm concentration @15% O 2

0 20 40 60 80 100 120 140 160 180

Figure Q. 1 - NOx Concentrations for Non-Electrical Electrcity Generating Facility Gas Turbines at Top 37 Emitting Facilities 

## Control Technology
An uncontrolled unit will typically be emitting well over 100 ppm of NOx. There are several methods of NOx control for gas turbin es, with differing levels of reduction. Steam or water injection involves the introduction of either medium into the combustor flame zone to lower the flame temperature, thus reducing NOx formation. Typically, this will reduce NOx emissions up to 60%. Dry low emissions (DLE or DLN) is a type of dry control which involves a major modification to the turbine’s combustion system. Unlike diffusion flames where the fuel

### 189 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
and air mixes and combusts at the same time, DLE combustors are premixed, where the air and fuel mix first and then are combusted to produce a lower flame temperature. In addition, these systems operate under lean cond itions, often with dual staged-combustion, further lowering NOx emissions. DLE technology can achieve NOx levels between around 10 and 45 ppm. Selective catalytic reduction (SCR) is the most effective technology that can achieve ultra low NOx emissions. The technology uses a precious metal catalyst that selectively reduces NOx in the presence of ammonia. Ammonia is injected in the flue gas stream where it reacts with NOx and oxygen in the presence of the catalyst to produce nitrogen and water vapor. The typical operating temperature of the exhaust gas is between 450 and 850 degrees F. 

## Proposed BARCT level and Emission Reductions

In command and control, SCAQMD Rule 1134 set limits for gas turbines for a range of sizes (ratings), with the limits varying between 9 and 25 ppm, corrected to 15% oxygen content. The 2005 NOx RECLAIM amendment proposed no new BARCTfor gas turbines, so these units have been only required to meet the Year 2000 Tier 1 emission level. The Ti er 1 emission level for natural gas and diesel fueled gas turbines in equivalent to 0.06 lb/MMBTU, which corresponds to approximately 17 ppm at 15% O 2 . This reference limit can be higher, depending on the efficiency of the unit. The majority of the RECLAIM units in this source category have not installed the controls to meet the Tier 1 emission level. For the non-electrical electricity ge nerating facility, non-refinery gas turbines in the top 37 facilities and based on ve ndor discussions and achieved in practice BACT installations, the proposed BARCT level for this source category is 2 ppm @15% O 2, and the control technology to achieve the NOx reductions is SCR. For units that are emitting less than 40 ppm NOx at 15% O2, a 2 ppm emission level is achievabl e with SCR only. In Figure Q.1, this would apply to the 7 units to the right of the chart. However, for those units emitting at 40 ppm, a 95 percent reduction is achievable. For the remainder of these units , a 95% reduction would achieve around 3 to 4 ppm. The power generating offshore units would achieve8 ppm at a 95% reduction for their current emission level since they have the highest emissi ons. The offshore gas compression turbines can achieve 5 ppm at a 95% reduction. A 2 ppm level would be achieva ble for the units emitting above 40 ppm if these units would install either wet or dry combustion controls to comply with the Tier 1 emission level. The single power generating gas turbine that is non-OCS currently operates with an SCR system permitted at 5 ppm for NOx. Staff believes that a replacement of the catalyst system would be sufficient to meet the 2 ppm BA RCT level. As a worst case, a present worth value was calculated from the same curve derived from existing refinery power generating units for a complete replacement of the SCR catalyst and equipment.

### 190 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

The emission reductions achieved from both subset s of units emitting above and below 40 ppm in the non-OCS sector are 1.04 tons per day. This is the incremental reduction from the Tier 1 level. The OCS units would add an additional 0.07 tons per day. 

## Cost Effectiveness
The total installed costs (TIC), which include equipment and installation costs were calculated by using vendor-supplied costs. The vendor-supplied co sts were for the SCR equipment only. This consists of the SCR housing, SCR catalyst, mixing ductwork, ammonia injection skid, PLC system, and CFD flow modeling. Installation costs can vary due to the type of facility and any site-specific limitations. To derive a reasonable estimate, the installation costs were calculated to be double (or 200%) of the equipment costs. Since an SCR installation at an offshore facility could be more complicated than a typical onshore installation, the in stallation costs were calculated at four times the equipment costs to account for the unique site considerations for this type of installation. The annual operating costs include catalyst replacement (replacement interval of three years), ammonia consumption (19%), and electrical consumption. A present worth value (PWV) was then calculated for each gas turbine using the TIC and annual costs (AC), and assumes a 4% inte rest rate and a 25-year equipm ent life per the equation below.
PWV = TIC + (15.622 x AC)

A cost effectiveness value was then calculated fo r each gas turbine using the present worth value and dividing by the incremental emission reductions (ER, in tons per day) from the Tier 1 level over the control equipment life (25 years). This method of calculating cost effectiveness utilizes the Discounted Cash Flow method (DCF). Cost Effectiveness = PWV / (ER x 365 x 25 years) Conversion to a Levelized Cash Flow (LCF) requi res a calculation using the following equation:
LCF Cost Effectiveness = (TIC x CRF) + AC / (ER x 365), where CRF is the Capital Recovery Factor assumin g a 4% interest rate over an equipment life of 25 years.

### 191 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

The cost effectiveness for non-el ectrical electricity generating facility, non-OCS gas turbines ranges from $4,700/ton to $35,900/ton ($7,500/ton to $57,500/ton, using LCF). This is to achieve a 95% reduction for those units emitting higher than 40 ppm and to achieve 2 ppm for those emitting lower than 40 ppm. For these gas turbines, the installation of SCR to treat NOx is cost effective. If the units emitting above 40 ppm install either wet or dry combustion controls to meet the Tier 1 emission level, then meeting 2 ppm is achievable. The cost effectiveness for the offshore ga s turbines ranges from $51,400/ton to $59,200/ton ($82,300/ton to $94,700/ton, using LCF). These figures reflect the power generating units achieving 8 ppm and the gas compression units me eting 5 ppm with SCR only. Since the cost effectiveness is above $50,000/ton and based on past rule makings, the OCS gas turbines are not considered cost effective in achieving the incremental NOx BARCT reductions from the Tier 1 level.
Table Q. 2 - Cost Effectiveness for Non-Electrical Electrcity Generating Facility Gas Turbines Unit TIC ($) AC ($) PWV ($) ER (tpd) DCF C.E. ($/ton) 1 2,786,139 707,847 13,844,125 0.081 18,716 2 2,858,592 687,666 13,601,308 0.085 17,537 3 2,780,064 727,308 14,142,076 0.084 18,518 4 2,583,085 297,613 7,232,403 0.015 52,748 5 2,604,485 352,643 8,113,472 0.015 59,174 6 2,608,400 329,730 7,759,450 0.015 56,592 7 2,252,960 68,133 3,317,340 0.007 51,422 8 2,259,305 75,832 3,443,960 0.007 53,384 9 2,269,455 68,955 3,346,666 0.007 51,876 10 1,517,898 68,321 2,585,211 0.009 33,250 11 1,519,272 65,261 2,538,781 0.008 35,916 12 1,531,680 69,149 2,611,931 0.009 33,594 13 1,516,755 63,256 2,509,164 0.008 35,497 14 2,320,584 437,781 9,159,602 0.156 6,478 15 1,443,846 80,740 2,705,163 0.025 11,658 16 1,442,694 92,373 2,885,744 0.016 19,823 17 2,765,694 555,222 11,439,367 0.269 4,666 18 2,438,727 389,347 8,521,114 0.128 7,310 19 2,432,730 397,575 8,643,648 0.135 7,019 20 * * 13,597,600 0.060 24,979

### 192 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

*PWV was determined from cost curve for refinery gas turbines (Figure C-5)



## Review of ETS’s Analysis for Meta l Heat Treating Furnaces above 150 MMBTU/hr
ETS, Inc. was commissioned by SCAQMD staff to provide an independent evaluation of the previously described BARCT and cost analysis. ETS concurs with the costing information and the conservative approach taken for calculating the costs for the possibly varied installations, given the site-specific aspects. ETS also concurs with the achievability of the reductions using SCR technology and no changes to th e cost estimates were made.

### 193 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015


## References for Non-Refinery, No n-Electrical Electrcity Generating Facility Stationary Gas Turbines

1. Best Available Retrofit Control Technol ogy Assessment – TXI Riverside Cement. SCAQMD, August 8, 2008.
2 . EPA Air Pollution Control Cost Manual . United States Environmental Protection Agency. Office of Air Quality Planning a nd Standards. 2002; EPA/452/B-02-001.
3. NOx RECLAIM BARCT Independent Evaluation of Cost Analysis Performed by SCAQMD Staff for BARCT in the Non-Refinery Sector . SCAQMD Contract #15343. ETS, Inc.; 2014.
4. Combustion and Fuels . Solar Turbines Incorporated Pr esentation, Luke Cowell, June 6, 2012.
5. Catalog of CHP Technologies: Combustion Turbines . United States Environmental Protection Agency - Combined Heatand Power Partnership, March 2015.
6. Alternative Control Techniques Document – NO x Emissions from Stationary Gas Turbines. U.S. Environmental Protection Agency, Officeof Air Quality Planning and Standards. January 1993; EPA-453/R-93-007.
7. AP-42, Fifth Edition: Compilation of Air Pollutant Emission Factors . United States Environmental Protection Agency, January 1995.

### 194 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix R – Non-Refinery Stati onary Internal Combustion Engines
Process Description
Stationary Internal Combustion Engines (ICEs) ar e used primarily to drive pumps, compressors, or to generate power. In command and control, Rule 1110.2 limits the NOx emissions for all gaseous and liquid-fueled engines that are above 50 brake horsepower (bhp). There are generally two types of engines, spark-ignited (SI) or compression ignited (CI) engines. SI engines ignite the air/fuel mixture with a spark while CI engines use the heat of compression to ignite the fuel that is injected into the combustion chamber. Engines can run at either stoichiometrically richor lean conditions, depending on the air to fuel ratio. Rich combustion corresponds to an air /fue l ratio that is fuel-rich while lean combustion corresponds to a fuel-lean air/fuel ratio. Small SIengines typically run as rich burn, but many larger units as well as CI engines operate under leanconditions. Usually, more air is inducted than is required for complete combustion and the resultant exhaust oxygen level is high (over 5%). Rich burn engines typically operate very close to stoichiometric conditions by drawing only the necessary air to combust the fuel. Spark-ignited engines are typically fired on gaseous fuels such as natural gas, while compression-ignited engi nes are fired on liquid fu els such as diesel. In 2005, there was no new BARCT proposed for this source category. Consequently, the emission factor has remained unchanged since 2000 (Tie r 1), which equates to about 57 ppm at 15% O 2 for natural gas-fired engines. During the 2008 am endment of Rule 1110.2, most stationary ICEs outside of RECLAIM (with the exception of biogas engines) were required to meet a NOx emission limit of 11 ppm at 15% O 2 by July 1, 2011. 

## Current Emission Inventory

Among the top thirty seven NOx emitting facilities in the RECLAIM universe, there are thirty one engines that are either major or large source units. Nine of these units are controlled with NSCR (non-selective catalytic reduction) as these engines are rich burn. Sixteen of these engines are SI lean burn units, while the remaining six are CI l ean burn units. The CI lean burn units are all operated on an offshore oil drilling platform (outer continental shelf, or OCS). Six of the SI lean burn units are two-stroke engines (See Table 1) . The engine sizes range from a little over 700 bhp to 5,500 bhp.

### 195 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table R. 1 - 2011 Emissions for Internal Co mbustion Engines atTop 37 Facilities Engine Type (at Top 37 Facilities) Number of engines 2011 emissions (tpd)
Lean Burn (Spark-Ignited) 16 0.34 Lean Burn (Compression Ignited), OCS 6 0.03
Rich Burn (Spark-Ignited) 9 0.02 Electrical Electrcity Generating Facility (2 stroke) 6 0.18

Total 37 0.56
There are also 6 additional ICEs that belong to a power producing facility, and the combined emissions from these engines were 0.18 tons per day in 2011. These engines are 2-stroke engines that are fired on diesel fuel due to the lack of access to natural gas. CI engines, which are fired on diesel, have the hi ghest NOx emission concentr ations in this source category. 2-stroke SI engines have higher NOx em issions than 4-stroke SI engines since the higher efficiencies in 2-stroke engines translate to a hotter combustion temperature that can create more NOx.ppm concentration @15% O2 CI, OCS

2-stroke SI

4-stroke SI

Figure R. 1 - NOx concentrations for Lean Burn ICEs at Top 37 Emitting Facilities

### 196 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Control Technology
The flue gas from rich burn engines is typicall y very low in excess oxygen. This enables NOx reduction to take place via N on-Selective Catalyti c Reduction technology (NSCR), which is inexpensive, readily installed, and simultaneous ly removes NOx, CO, and VOC. NSCR (or threeway) catalysts have been commercially available for many years and can achieve NOx removal efficiencies of over 90 percent. The catalyst redu ces NOx to nitrogen and oxygen in the presence of CO and VOC, while simultaneously oxidizing CO and VOC to form carbon dioxide and water. Precise air/fuel ratio control is required since the catalytic reactions must occur within a narrow air/fuel ratio band. With lean burn exhaust the higher oxygen conten t does not allow effective removal of NOx with NSCR. On this basis, CO and VOC will have a preferential reaction with the oxygen instead of the NOx. In this case, Selective Catalytic Reducti on (SCR) is the technology of choice. Oxygen is an essential ingredient in the SCR reactions and the excess oxygen in the exhaust gas provides this. Ammonia (or urea) is injected in the flue gas stream where it reacts with NOx and oxygen in the presence of a catalyst to produce nitrogen an d water vapor. The catalyst material is typically a base metal catalyst such as titanium dioxide or vanadium pentoxide, and operates within a temperature range of 450 to 850 F. 

## Proposed BARCT level and Emission Reductions

The 2008 amendment to Rule 1110.2 establishe d a NOx emission level of 11 ppm @15% O 2 for most IC engines. The technology identified fo r rich burn engines was NSCR while the technology identified for lean burn engines was SCR. The effective date for complying with the final rule limit has been in effect for over four years. NSCRis feasible for rich burn engines and SCR is feasible for both two-stroke and four-stroke lean-burn engines. The 2005 RECLAIM amendment proposed no new BARCT for IC engines, so these units have been only required to meet the Year 2000 Tier 1 emission level. For th e non-electrical electricity generating facility engines in the top 37 emittin g facilities, the proposed BARCT level is 11 ppm @15% O 2 . The rich burn engines in this category have all been retrofitted with NSCR and most of them meet the proposed BARCT level. These three way catalysts were installed to control CO and VOC for compliance with Rule 1110.2 requireme nts by July 1, 2011, since these pollutants are not governed under RECLAIM rules. There is an added benefit withthree way catalysts because they also control NOx and this has resulte d in emission reductions for these engines. For lean burn engines, however, the control technolog y to achieve the NOx reductions is SCR. If all the non-OCS engines in this category were to ach ieve the proposed BARCT level, the emission reductions from the Tier 1 level w ould be 0.84 tons per day. There is a portion of this reduction

### 197 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 that is attributed to the rich burn engines and it amounts to 0.07 ton per day. Recent source tests indicate that the majority of th ese engines are already meeting the proposed BARCT level of 11 ppm. It is assumed that these engines will continue to meet the 11 ppm emission level. The electrical electricity generating facility engines, since they are 2-stroke diesel engines, are more difficult in terms of reducing NOx emissions. These engines are isolated and there is no other fuel backup. The unique nature of these en gines provides a challenge with regards to very low allowable backpressures, whic h makes SCR an inflexible treatment option. Therefore, there is no new proposed BARCT for electrical electricity generating facility ICEs. The OCS engines in this category will not be subject to the new BARCT because the engines at offshore platforms run rig generators that are ofte n variable in load. SCR systems need a more constant load so that the proper operating temp eratures can be sustained for effective NOx removal.


## Cost Effectiveness
The total installed costs (TIC), which include equipment and installation costs were calculated by using both vendor-supplied costs along with insta llation costs from an existing SCR installation on a lean-burn engine. The vendor-supplied costs werefor the SCR equipment only. This consists of the SCR housing, SCR catalyst, mixing ductwork, expansion joint, urea injection skid (control system, pump, dosing unit), and an air compression/drying system. Installation costs can vary due to the type of facility and any site-specific limitations. To derive a reasonable estimate, the costs from an achieved in practice SCR installation on a lean-burning engine were used. This engine is located at Or ange County Sanitation District (OCSD), is fired on natural gas and digester gas, and is retrofitted with an oxidation catalyst and SCR. It was installed in 2009 and has been consistently been meeting the 11 ppm NOx limit of Rule 1110.2. The catalyst system had to be placed on an extern ally constructed platform because of the site constraints inside the engine building. These add itional costs have been included as part of this analysis in anticipation of any supplemental s upport structures necessary to accommodate the SCR system. The 2009 dollar figures for the OCSD inst allation were raised to 2013 dollar values using the Marshall & Swift Index inflation factor. The installation costs for all the affected engines were scaled by horsepower based on the cost s for this installation at OCSD. The annual operating costs include catalyst repla cement, reagent consumption, reagent delivery system maintenance, and electrical consumptio n. The annual costs for the OCSD installation assume a 3 year SCR catalyst replacement interval and were scaled for the engines in this source category by engine horsepower. For two-stroke engines, a very conservative replacement interval

### 198 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 of one year was selected due to the potentially more contaminated exhaust gas stream (ash, soot) from this type of engine. A present worth value (PWV) was then calculated for each engine using the TIC and annual costs (AC), and assumes a 4% interestrate and a 25-year equipmen t life per the equation below.
PWV = TIC + (15.622 x AC) A cost effectiveness value was then calculated for each engine using the present worth value and dividing by the incremental emi ssion reductions (ER, in tons per day) from the Tier 1 level over the control equipment life (25 years). This method of calculating cost effectiveness utilizes the Discounted Cash Flow method (DCF). Cost Effectiveness = PWV / (ER x 365 x 25 years) Conversion to a Levelized Cash Flow (LCF) requi res a calculation using the following equation:
LCF Cost Effectiveness = (TIC x CRF) + AC / (ER x 365), where CRF is the Capital Recovery Factor assuming a 4% interest rate over an equipment life of 25 years.
Table R. 2 - Cost Effectiveness for Lean-Burn, Non-OCS ICEs Unit TIC ($) AC ($) PWV ($) ER (tpd) DCF C.E. ($/ton)

1 890,182 36,625 1,462,338 0.036 4,500 2 890,182 36,625 1,462,338 0.033 4,900 3 890,182 36,625 1,462,338 0.033 4,800 4 890,182 36,625 1,462,338 0.034 4,700 5 890,182 36,625 1,462,338 0.035 4,600 6 1,386,291 82,640 2,677,289 0.043 6,900 7 485,628 25,696 887,048 0.019 5,000 8 485,628 25,696 887,048 0.019 5,000 9 1,307,772 77,475 2,518,084 0.038 7,300 10 485,628 25,696 887,048 0.019 5,100 11 1,307,772 77,475 2,518,084 0.037 7,500 12 2,319,249 100,719 3,892,680 0.084 5,000 13 2,319,249 100,719 3,892,680 0.084 5,000 14 2,319,249 100,719 3,892,680 0.085 5,000 15 2,319,249 100,719 3,892,680 0.083 5,200 16 2,319,249 100,719 3,892,680 0.084 5,000

### 199 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The cost effectiveness for non-electrical electricity generating facility IC engines ranges from $4,500/ton to $7,500/ton ($7,200/ton to $12,000/ton, using LCF). For these engines, the installation of SCR to treat NOx is cost effective. 

## Review of ETS’s Analysis for Non- Refinery Stationary Internal Combustion Engines
ETS, Inc. was commissioned by SCAQMD staff to provide an independent evaluation of the previously described BARCT and cost analysis. ETS concurs with the costing information and the conservative approach taken for calculating the costs for the possibly varied installations, given the site-specific aspects. ETS also concurs w ith the achievability of the reductions using SCR technology and no changes to th e cost estimates were made.


## References for Non-Refinery St ationary Internal Combustion Engines

1. EPA Air Pollution Control Cost Manual . United States Environmental Protection Agency. Office of Air Quality Planning a nd Standards. 2002; EPA/452/B-02-001.
2. NOx RECLAIM BARCT Independent Evaluation of Cost Analysis Performed by SCAQMD Staff for BARCT in the Non-Refinery Sector . SCAQMD Contract #15343. ETS, Inc.; 2014.
3. AP-42, Fifth Edition: Compilation of Air Pollutant Emission Factors . United States Environmental Protection Agency, January 1995.
4. Alternative Control Techniques Document – NOxEmissions from Stationary Reciprocating Internal Combustion Engines. U.S. Environmental Protection Ag ency, Office of Air Quality Planning and Standards. January 1993; EPA-453/R-93-032.
5. Retrofit Digester Gas Engine with Fuel Gas Clean-up and Exhaust Emission Control Technology. SCAQMD Contract #10114, Orange Count y Sanitation District, July 2011.

### 200 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix S – Non-Refiner y Boilers >40 MMBTU/hr
In the top 37 emitting facilities, th ere are four boilers that are above 40 MMBTU/hr. They range between 49 and 247.3 MMBTU/hr. The 2005 BARCT le vel for these units was 9 ppm at 3% O 2 . The incremental NOx reduction going from 9 pp m to a proposed BARCT level of 2 ppm would be 0.01 tons per day. SCR would be the technology of choice for achievin g NOx reductions for larger boilers. The costs for retrofitting these units were estimated from the ETS-adjusted vendor quotes for a similar sized installation for the sodium silicate furnace. The present worth value for the installation in on a 56.6 MMBTU/hr combustion furnace is $4,602,745. The pr esent worth value for the largest unit was calculated from the cost curve developed f or refinery boilers and heaters (Figure B-3).

The DCF cost effectiveness for all of the four units were calculated to be above $150,000 per ton of NOx. Therefore, retrofitting with SCR would not be cost effective. ETS concurs that the costs for installing SCR would not be cost effective for this source category.
Table S. 1 - Cost Effectiveness for Non-Refinery Boilers >40 MMBTU/hr
Unit Rating (MMBTU/hr) PWV ($) Incremental Emission Reductions (tpd) DCF Cost Effectiveness ($/ton) 1 57 4,602,745 0.003 182,107 2 62.5 4,602,745 0.003 153,938 3 49 4,602,745 0.0001 6,447,425 4 247.3 13,527,310 0.004 380,515

### 201 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix T – Survey Questionnair es for Non-Refinery Sector
South Coast Air Quality Management 2013 NOx RECLAIM Survey Questionnaire for Non-Refineries (Due Date: July 12, 2013)
Facility Contact 1. Please provide the facility contact for this project: Name: ________________________________ Title: ________________________________ Phone Number: _________________________ Email Address: _________________________
Top NOx Emitting Equipment or Processes (* The attached list may contain the information requested) 2. * Please verify the attached list for the top 10 NOx emitting equipment and processes at your facility in Compliance Year 2011 and their emissions. 3. Please mark on the attached list the NOx control equipment installed after the 2005 NOx RECLAIM amendment Boilers, Heaters, Furnaces, Kilns, Turbines, and Cogeneration Units (Major and Large Sources) 4. For each major and large combustion source at your facility, please verify the following information in the attached list, and provide in formation if the attached list does not contain this specific information: k. * Device description, Device ID, Process Name l. * Emissions in CY 2011 (tons per day) m. * Maximum unit rating (MMBTU/hr) n. * Type of fuel used o. Fuel usage rate and BTU content of fuel p. Flue gas flow rate (million dry standard cubic feet), temperature, oxygen and water content q. Representative flue gas analysis and fuel gas analysis r. NOx concentration in the exhaust flue gas (ppmv at 3% O 2 or ppmv at 15% O 2 ). Please attach a copy of the most current source test reports/results. s. Allowable back pressure t. * Control technology used (e.g. LNB, SCR, NOx scrubber) 5. For the control technology identified in item #4 above:

### 202 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 h. Device description, Device ID i. Manufacturer’s name and performance. Please attach a copy of manufacturer's specification/guarantee j. Design parameters (e.g. maximum flue gas flow rate, inlet and outlet ppmv, ammonia slip) k. If the control device is shared between multiple NOx emitting sources, please identify all other sources that are vented to this control device l. Dimension of the add-on NOx control device (e.g. length, width, height of the SCR, catalyst volume) m. Cost information (capital costs, installation costs, and annual operating costs) n. Installation date (e.g. July 2005) 6. Provide drawings that show location and distances between th e major and large NOx sources at the facility. Reports Submitted Under the U.S. EPA Consent Decree 7. If the facility must install control technol ogy to reduce the NOx emissions under an U.S. Environmental Protection Agency (EPA)’s consen t decree, please provide the District a copy of the most recent reports/test results submitted to the EPA related to this consent decree. Feasible Control Approach Including Energy Efficiency Project 8. List any feasible control approach that your facility plans to install, including replacement of the existing units with higher energy efficient units, to further reduce your facility’s NOx emissions and green-house gase s. Provide a brief descrip tion of the control approach, manufacturer's name, estimated emissi on reductions, and cost information.

If you have any questions, please contact either: Kevin Orellana (909) 396-3492, korellana@aqmd.gov , or

Gary Quinn, P.E. (909) 396-3121, gquinn@aqmd.gov
Please submit information via e-mail by July 12, 2013 to Kevin Orellana and Gary Quinn. Thank you for participating in the Survey.

### 203 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Part III – RTC Reduction Approaches
Part III contains information pertinent to the RTC reductions estimation. Part III contains three appendices: Appendix U contains a discussion on sta ff’s approaches and calculation to determine the RTC reductions based on the 2015 BARCT levels assessed in Part I for the refinery sector and Part II for the non-refinery s ector. Staff’s calculation were al so based on the 2011 audited NOx emissions for all NOx RECLAIM facilities except electrical electricity generating facilities. For electrical electricity generating facilities, staff used the 2012 baseline emissions. Appendix V contains the 2011 audited emissi ons, and Appendix W contains the 2012 baseline emissions for electrical electricity generating facilities.

### 204 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix U – Staff’s Proposal and CEQA Alternatives Staff has considered several options to determin e the most appropriate RTC shave distribution to effect emission reductions that will protect the environment, satisfy the state and federal CAA requirements, and satisfy AQMP commitments, while concurrently providing for growth and safeguards for the continued functioning of th e RECLAIM program. The RTC reductions with the application of BARCT total 14.79 tons per day. However, an adjustment is proposed to the total RTC reductions to account for issues that have been raised by stakeholders regarding the BARCT analysis. These issues primarily focused on the potential uncertainties of the control costs for refinery boilers and heaters and the reliability and consistency in maintaining controlled NOx concentrations for the coke calcining unit. Withthese adjustments, the RTC reduction that would be applied for the shave approaches would total 14 tons per day by 2023. The shave proposals under consideration affectfour major groups within the NOx RECLAIM universe:

x Major Refineries and Investors

x Top 90% of RTC Holders

x Others (Bottom 10 percent of RTC Holders) The bottom 10 percent of RTC holders would be exempted from an RTC reduction under the staff proposal. It should be noted that the newer electrical electricity generating facilities among the top 90% of RTC are subject to NSR holding requireme nts for their equipment, which is mostly at BACT. Staff is proposing a Regional NSR Holdin g Account for these facilities in order provide some relief given their ongoing NSR obligations of holding RTCs at the equipment’s potential to emit level at the beginning of each compliance year. 

## Staff Proposal Calculation of Remaining Emissions The remaining emissions are determined by summing the calculated remaining emissions in 2023 with economic growth factors applied and with BARCT applie d for both the refinery and nonrefinery sectors (Tables 5.1 and 5.2). The remaining emissions total 10.23 tons per day. Emissions accounting for new RECLAIM facilities since the 2011 base year are added and a 10% compliance margin is applied, so the remaining emissions become 11.33 tons per day. Next, an activity adjustment, accounting for atypical operation cond itions in 2011, is applied which results in 11.72 tons per day remaining. Lastly, a BARCT uncertainty adjustment is applied to account for uncertainties in the analysis. After all the adju stments, the total remaining emissions are 12.51 tons per day. This is equivalent to a 14 ton per day reduction from the allocation cap of 26.51 tons per day. Figure U.1 illustrates the ad justments and the total RTC reduction.

### 205 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Figure U.1 – 2023 Adjustments and Allocation Target



### 10.23 11.33 11.72 12.51 12.51 14

0 5 10 15 20 25 30

2023 Emissions at 2015 BARCT New Facilities and 10% Compliance Margin Activity Adjustment BARCT Uncertainty Adjustment 2023 Staff ProposalTPD (Tons Per Day)

The staff proposal for the shave would affect th e top 90 percent of RTC holders, which includes major refinery facilities. Investors would also be shaved at this level. Refineries and Investors are designated as Category A facilities in Table U.1. Non-major refinery facilities in the top 90% of RTC holders and electrical electricity generating facilities among the top 90% of RTC holders would be included in the shave as Category B1 and B2 facilities, respectively. The reductions for the facilities subject to the shave would be weighted by the BARCT reduction contribution for major refineries and all other facilities, with investors grouped with the major refineries. RTC holdings for major refineries a nd investors would be shaved by 66 percent. For non-major refineries and all other facilities among the top 90 percent of RTC holders, the RTC holdings would be shaved by 49 percent. See Tables U.1 and U.2.

### 206 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table U.1 - List of 56 Affected Facilities Plus Investors HOLDINGS AS SEPTEMBER 22, 2015 USING TOP 90% RTC HOLDINGS LIST FROM 3/20/15 ID Name Category 148553 VERNON CITY, LIGHT & POWER DEPARTMENT A 700144 OLDUVAI GORGE, LLC A 700161 KOCH SUPPLY & TRADING, LP A 700084 SHELL NORTH AMERICA (US), L.P. A

16352 SO CAL EDISON CO A 158300 CITY OF ONTARIO A 710 TEXACO EXPLORATION & PRODUCTION INC. A 700050 KEN BARKER A 800042 ECO PETR INC (EIS USE ONLY) A 101337 NATIONAL OFFSETS A 800253 UNION CARBIDE CORP A 169514 TITAN TERMINAL AND TRANSPORT INC A 700170 ABATEMENT CAPITAL LLC A 700175 TWIN EAGLE RESOURCE MANAGEMENT LLC A 700177 GREY EPOCH LLC A 800030 CHEVRON PRODUCTS CO. A 800089 EXXONMOBIL OIL CORPORATION A 174655 TESORO REFINING & MARKETING CO, LLC A 800436 TESORO REFINING AND MARKETING CO, LLC A 171107 PHILLIPS 66 CO/LA REFINERY WILMINGTON PL A 800026 ULTRAMAR INC A 166073 BETA OFFSHORE B1 800128 SO CAL GAS CO B1

46268 CALIFORNIA STEEL INDUSTRIES INC B1 171109 PHILLIPS 66 COMPANY/LOS ANGELES REFINERY A 174591 TESORO REFINING & MARKETING CO LLC, CAL A 169754 OXY USA INC B1 7427 OWENS-BROCKWAY GLASS CONTAINER INC B1 18931 TAMCO B1 800183 PARAMOUNT PETR CORP B1

43201 SNOW SUMMIT INC B1 172005 NEW- INDY ONTARIO, LLC B1 800189 DISNEYLAND RESORT B1 156741 HARBOR COGENERATION CO, LLC B1 151798 TESORO REFINING AND MARKETING CO, LLC A

11435 PQ CORPORATION B1

4242 SAN DIEGO GAS & ELECTRIC B1

### 207 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

17953 PACIFIC CLAY PRODUCTS INC B1 800127 SO CAL GAS CO B1 180367 LINN OPERATING, INC B1 124838 EXIDE TECHNOLOGIES B1 800181 CALIFORNIA PORTLAND CEMENT CO B1

51620 WHEELABRATOR NORWALK ENERGY CO INC B1

5973 SO CAL GAS CO B1 3968 TABC, INC B1 8582 SO CAL GAS CO/PLAYA DEL REY STORAGE FACI B1 178639 ECO SERVICES OPERATIONS LLC B1 800153 US GOVT, NAVY DEPT LB SHIPYARD B1 8547 QUEMETCO INC B1 1073 BORAL ROOFING LLC B1 115394 AES ALAMITOS, LLC B2 115663 EL SEGUNDO POWER, LLC B2 800074 LA CITY, DWP HAYNES GENERATING STATION B2 800075 LA CITY, DWP SCATTERGOOD GENERATING STN B2 115536 AES REDONDO BEACH, LLC B2 160437 SOUTHERN CALIFORNIA EDISON B2 115315 NRG CALIFORNIA SOUTH LP, ETIWANDA GEN ST B2 152707 CPV SENTINEL LLC B2 115389 AES HUNTINGTON BEACH, LLC B2 4477 SO CAL EDISON CO B2 146536 WALNUT CREEK ENERGY, LLC B2 128243 BURBANK CITY,BURBANK WATER & POWER,SCPPA B2 115314 LONG BEACH GENERATION, LLC B2 153992 CANYON POWER PLANT B2 800193 LA CITY, DWP VALLEY GENERATING STATION B2

25638 BURBANK CITY, BURBANK WATER & POWER B2 800168 PASADENA CITY, DWP B2 155474 BICENT (CALIFORNIA) MALBURG LLC B2 127299 WILDFLOWER ENERGY LP/INDIGO GEN., LLC B2 129816 INLAND EMPIRE ENERGY CENTER, LLC B2 700126 GENERAL ELECTRIC COMPANY B2

COUNTS Category Description A Major Refineries 9 A Investors (Counted as 1 Facility) 1

B1 Top 90% Holder, Non-Electric al Electrcity Generating Facilities 26

B2 Top 90% Holder, Electrical Electrcity Generating Facilities 21 TOTAL 57

### 208 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table U.2 - RTC Reduction Calculation

Refinery Reductions Beyond 2005 BARCT, tpd 6.00 Non-Refinery Reductions Beyond 2005 BARCT, tpd 2.77 Total, tpd 8.77 Refinery Contribution to Emission Reduction (6.00 / 8.77 x 100) 68% Non-Refinery Contribution to Emission Reduction (2.77 / 8.77 x 100) 32%

Total RTC Allocation in 2023 26.51 Remaining 2023 Emissions After BARCT and Growth 11.72 Minus BARCT Uncertainty Adjustment 0.79 Total RTC Reduction (26.51 - 11.72 - 0.79) 14 Weighted Reduction for Refi nery (14.00 x 68%) 9.58 Weighted Reduction for Non-Refinery (14.00 x 32%) 4.42 Total Reduction 14
Major Refinery + Investor Holdings for Top 90% 14.57 Non-Major Facility Holdings + All Electrical El ectrcity Generating Facility Holdings for Top 90% 9.09 RTC Holdings for Top 90% of Holders, Including Investors (14.57 + 9.19) 23.66
Remaining Major Refinery + Investor RTC Holdings (14.57 - 9.58) 4.99 % Shave to this Sub-Universe (9.58 / 14.57) x 100 66%
Remaining Non-Refinery RTC Holdings (9.09 - 4.42) 4.67 % Shave to this Sub-Universe (4.42 / 9.09) x 100 49% RTC Reductions = Current Holdings (26.51 tpd) – Remaining Emissions in 2023 (11.72 tpd) = 14.79 tpd Total RTC Reductions = 14.79 tpd – (BARCT adjustment of 0.79 tpd) = 14 tpd 

## CEQA Alternatives CEQA Alternative 1: This approach would be an acros s the board RTC reduction and would affect all RECLAIM facilities and investors. The RTC holdings would be shaved by 53 percent overall.
CEQA Alternative 2: This approach, the most stringent, would also be an across the board RTC reduction affecting all RECLAIM facilities and investors, but would not include the 10 percent compliance margin or the BARCT adjustment for refinery equipment. The total RTC reduction would be 15.82 tons per day under this approachand the RTC holdings would be shaved by 60 percent overall.Draft Final Staff Report – NOx RECLAIM 

### 209 October 6November December 4, 2015
CEQA Alternative 3: This approach has been proposed by industry representatives and is an across the board shave that would affect all RECLAIM facilities and investors. For this calculation, the base year emissions at the propos ed BARCT level would be subtracted from the base year emissions at the previous BARCT le vel (Year 2000 or 2005). The result would be an RTC reduction of 33 percent to all RECLAIM facilities and investors.
CEQA Alternative 4: This is the “No Project” approach and no RTC reduction would be applied to any RECLAIM facility or investor.
CEQA Alternative 5: This approach would affect all RECLAIM facilities and investors. The RTC reductions would be weighted by the BARCT reduction contribution for major refineries and all other facilities, withinvestors grouped with the major re fineries. RTC holdings for major refineries and investors would be shaved by 66 percent. For non-major re fineries and all other facilities, the RTC holdings would be shaved by 37 percent. Table U.3 - NOx RECLAIM Shave Op tions and CEQA Alternatives

Major Refineries/

Investors Non-Major Facilities Electrical Electrcity Generating

Facilities Bottom 10% of Holders

Staff Proposal Under Consideration Staff Proposal Shave applied to 90% of RTC Holders (Weighted by BARCT Reduction Contribution) 56 total facilities, plus investors as 1 company, and includes 47 non-major refinery facilities 6 6 7 % (9 Facilities) 4 9 6 % (26 Facilities) 4 9 6 % (21 Facilities) 0% (219 Facilities)

CEQA Alternatives Under Consideration CEQA Alternative #1 Across the Board Affects all facilities and investors 53% 53% 53% 53%

CEQA Alternative #2 Most Stringent Approach Across the Board without 10% Compliance Margin 60% 60% 60% 60%

CEQA Alternative #3 Industry Approach Across the Board: Difference between previous BARCT and new BARCT 33% 33% 33% 33%

CEQA Alternative #4 No Project 0% 0% 0% 0%

CEQA Alternative #5 Weighted by BARCT Reduction Contribution Affects all facilities and investors 66% 37% 37% 37%

### 210 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015



## Tradable/Usable and Non-Tradable/Non-Usable Factors in Rule 2002(f)(1)(B) and (C) The Tradable/Usable NOx Adjustment Factor is derived by dividing the amount of RTCs remaining after the shave for each compliance year by the total holdings prior to the beginning of the shave (September 22, 2015). For those facilitie s subject to subparagraph (f)(1)(B) [listed in Rule 2002 Table 7] the total Infinite Year Block (IYB) total holdings in 2022 prior to the beginning of the shave is 14.57 tons per day. Similarly, for those facilities subjectto subparagraph (f)(1)(C) [listed in Rule 2002 Table 8] the total holdings prior to the beginning of the shave is 9.09 tons per day. Both of these values are pres ented in Table U.2 of this report. The proposed RTC reduction for each compliance year is presented in Chapter 5 of this report are: 2016: 4 tons per day 2017: 0 tons per day 2018: 2 tons per day 2019: 2 tons per day 2020: 2 tons per day 2021: 2 tons per day 2022 2 tons per day The proportion of RTC reductions based on initial holdings and re maining RTC for the Table 7 and Table 8 facilities are as follows:

Compliance Year Table 7 Facilities Table 8 Facilities

Reductions (TPD) A i Remaining (TPD) Reductions (TPD) B i Remaining (TPD) 2016: 2.74 11.83 1.26 7.82 2017: 0 11.83 0 7.82 2018: 1.37 10.46 0.63 7.20 2019: 1.36 9.11 0.64 6.56 2020: 1.37 7.74 0.63 5.93 2021: 1.37 6.37 0.64 5.30 2022 1.38 4.99 0.63 4.67 The Tradable/Usable NOx Adjustment Factor is calculated as follows: Table 7 Facilities = A i/14.57 Table 8 Facilities = B i/9.09

### 211 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The Non-tradable/Non-usable NOx Adjustment Fact or is derived by dividing the annual amount of RTC reductions starting in 2016 by the total holdings prior to the beginning of the shave. For the Table 7 and 8 facilities the annual amount of N on-tradable/Non-Usable holdings would be as follows:

Compliance Year Table 7 Facilities RTC Reductions Table 8 Facilities RTC Reductions
Annual (C i ) (TPD) Adjustment Factor Annual (D i ) (TPD) Adjustment Factor 2015 0 0 0 0 2016 2.74 0.188 1.26 0.139 2017 0 0 0 0 2018: 1.37 0.094 0.63 0.069 2019: 1.37 0.093 0.63 0.07 2020: 1.37 0.094 0.63 0.069 2021: 1.37 0.094 0.63 0.07 2022 1.37 0.094 0.63 0.069 2023 and after 0 0 0 0 The Non-tradable/Non-usable NOx Adjustment Factor is calculated as follows: Table 7 Facilities = C i/14.57 Table 8 Facilities = D i/9.09 

## Regional NSR Holding Account In addition to the Non-tradable/Non-usable ac count, newer electrical electricity generating facilities subject to the shave with ongoing NSR holding requirements (entered RECLAIM after October 15, 1993) will have access to this acco unt under specific circumstances, which will be funded by the shaved portion of each affected faci lity’s holdings for every compliance year of the shave beginning in 2017. At the end of the sh ave, 49% of the holdings from newer electrical electricity generating facilities subject to NSR requ irements will be held in the Regional account. For the first year of the shave, however, there will be no portion that will go into the account. The funding will begin on the second year, when the non- tradable account holdings expire. Access to credits for the purposes of NSR or compliance with annual emissions in the first year of the shave will be provided by the non-tradab le account if the rolling average RTC threshold price trigger is reached or in a State of Emergency for power generation declared by the Governor in the Basin. The table below contains the yearly and cumu lative holdings that will go into the account:

### 212 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Compliance Year Holdings for Regional NSR Holding Account (tpd) Cumulative Balance (tpd) 2016 0 0 2017 0.237 0.237 2018 0 0.237 2019 0.118 0.355 2020 0.118 0.473 2021 0.118 0.591 2022 0.118 0.709 2023+ 0.118 0.827 The total holdings that will be contained in th e Regional NSR Holding Ac count programmatically will be 0.83 tons per day in 2023 and beyond. The list of electrical electricity generating facilities in the top 90% of RTC holders that are subject to NSR holding requirements and are eligible to use the Regional Account for NSR purposes are as follows: Facility ID Facility Name 160437 SOUTHERN CALIFORNIA EDISON 152707 CPV SENTINEL LLC 146536 WALNUT CREEK ENERGY, LLC 128243 BURBANK CITY,BURBANK WATER & POWER,SCPPA 115314 LONG BEACH GENERATION, LLC 153992 CANYON POWER PLANT 155474 BICENT (CALIFORNIA) MALBURG LLC 127299 WILDFLOWER ENERGY LP/INDIGO GEN., LLC 129816/ 700126 INLAND EMPIRE ENERGY CENTER, LLC/ GENERAL ELECTRIC COMPANY Table 9 in Rule 2002 lists these facilities and the sp ecific yearly RTC balances that will go to the Regional NSR Holding account from compliance year 2016 and beyond. In 2023, the account would reach full funding and will carry over every year for the purposes of fully or partially fulfilling each facility’s NSR demonstration.

### 213 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix V – 2011 Audited Emi ssions of 20 tons per day

The 2011 audited NOx emissions for the 281 faci lities in RECLAIM are shown in Table V-1.

Table V. 1 - 2011 Audited Emissions

2011 Emissions (lbs) 2011 Emissions (tpd) 1 131003 BP WEST COAST PROD.LLC BP CARSON REF. 1,231,852 1.69 2 131249 BP WEST COAST PRODUCTS LLC,BP WILMINGTON 407,394 0.56 3 151798 TESORO REFINING AND MARKETING CO, LLC 93,488 0.13 4 171107 PHILLIPS 66 CO/LA REFINERY WILMINGTON PL 1,143,902 1.57 5 171109 PHILLIPS 66 COMPANY/LOS ANGELES REFINERY 673,652 0.92 6 800026 ULTRAMAR INC (NSR USE ONLY) 534,363 0.73 7 800030 CHEVRON PRODUCTS CO. 1,425,393 1.95 8 800089 EXXONMOBIL OIL CORPORATION 1,602,233 2.19 9 800183 PARAMOUNT PETR CORP (EIS USE) 104,249 0.14 10 800436 TESORO REFINING AND MARKETING CO, LLC 1,171,965 1.61 Total Refineries 11.49 1 4242 SAN DIEGO GAS & ELECTRIC 142,751 0.20 2 4477 SO CAL EDISON CO 137,290 0.19 3 5973 SO CAL GAS CO 88,258 0.12 4 7427 OWENS-BROCKWAY GLASS CONTAINER INC 135,486 0.19 5 11435 PQ CORPORATION 81,270 0.11 6 15504 SCHLOSSER FORGE COMPANY 52,331 0.07 7 18931 TAMCO 226,012 0.31 8 22911 CARLTON FORGE WORKS 48,839 0.07 9 46268 CALIFORNIA STEEL INDUSTRIES INC 464,990 0.64 10 51620 WHEELABRATOR NORWALK ENERGY CO INC 89,025 0.12 11 114801 RHODIA INC. 48,878 0.07 12 115389 AES HUNTINGTON BEACH, LLC 98,993 0.14 13 115394 AES ALAMITOS, LLC 80,929 0.11 14 119907 BERRY PETROLEUM COMPANY 131,857 0.18 15 124838 EXIDE TECHNOLOGIES 62,824 0.09 16 128243 BURBANK CITY,BURBANK WATER & POWER,SCPPA 49,983 0.07 17 129497 THUMS LONG BEACH CO 66,364 0.09 18 129816 INLAND EMPIRE ENERGY CENTER, LLC 105,857 0.15 19 160437 SOUTHERN CALIFORNIA EDISON 204,132 0.28 20 166073 BETA OFFSHORE 391,977 0.54 21 171960 TIN, INC. DBA INTERNATIONAL PAPER 327,637 0.45 22 800074 LA CITY, DWP HAYNES GENERATING STATION 205,022 0.28 23 800075 LA CITY, DWP SCATTERGOOD GENERATING STN 103,988 0.14 24 800128 SO CAL GAS CO (EIS USE) 461,243 0.63 25 800193 LA CITY, DWP VALLEY GENERATING STATION 166,413 0.23 26 800330 THUMS LONG BEACH 49,657 0.07 27 800335 LA CITY, DEPT OF AIRPORTS 73,245 0.10 Total non-refineries 5.61 Total for top 37 emitting facilities 17.10

### 214 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

1 800189 DISNEYLAND RESORT 47,216 0.06 2 8547 QUEMETCO INC 46,831 0.06 3 126498 STEELSCAPE, INC 46,420 0.06 4 101656 AIR PRODUCTS AND CHEMICALS, INC. 44,275 0.06 5 8582 SO CAL GAS CO/PLAYA DEL REY STORAGE FACI 42,884 0.06 6 800168 PASADENA CITY, DWP (EIS USE) 41,370 0.06 7 115536 AES REDONDO BEACH, LLC 40,890 0.06 8 9755 UNITED AIRLINES INC 40,626 0.06 9 94872 METAL CONTAINER CORP 39,730 0.05 10 800080 LUNDAY-THAGARD COMPANY 39,275 0.05 11 155474 BICENT (CALIFORNIA) MALBURG LLC 38,772 0.05 12 105903 PRIME WHEEL 37,852 0.05 13 43436 TST, INC. 35,778 0.05 14 148236 AIR LIQUIDE LARGE INDUSTRIES U.S., LP 33,031 0.05 15 3417 AIR PROD & CHEM INC 32,660 0.04 16 14495 VISTA METALS CORPORATION 30,433 0.04 17 139010 RIPON COGENERATION LLC 30,419 0.04 18 16639 SHULTZ STEEL CO 30,415 0.04 19 47781 OLS ENERGY-CHINO 29,938 0.04 20 550 LA CO., INTERNAL SERVICE DEPT 29,202 0.04 21 118406 CARSON COGENERATION COMPANY 28,760 0.04 22 155877 MILLERCOORS, LLC 28,439 0.04 23 800409 NORTHROP GRUMMAN SYSTEMS CORPORATION 27,489 0.04 24 800037 DEMENNO/KERDOON 26,951 0.04 25 16338 KAISER ALUMINUM FABRICATED PRODUCTS, LLC 25,667 0.04

1 136 PRESS FORGE CO 25,407 0.03 2 3704 ALL AMERICAN ASPHALT, UNIT NO.01 24,416 0.03 3 16642 ANHEUSER-BUSCH LLC., (LA BREWERY) 23,205 0.03 4 35302 OWENS CORNING ROOFING AND ASPHALT, LLC 23,022 0.03 5 800170 LA CITY, DWP HARBOR GENERATING STATION 22,609 0.03 6 115663 EL SEGUNDO POWER, LLC 21,639 0.03 7 11887 NASA JET PROPULSION LAB 21,140 0.03 8 153992 CANYON POWER PLANT 21,077 0.03 9 17953 PACIFIC CLAY PRODUCTS INC 20,635 0.03 10 346 FRITO-LAY, INC. 20,492 0.03 11 68042 CORONA ENERGY PARTNERS, LTD 19,286 0.03 12 18294 NORTHROP GRUMMAN CORP, AIRCRAFT DIV 18,299 0.03 13 3585 R. R. DONNELLEY & SONS CO, LA MFG DIV 16,710 0.02 14 800016 BAKER COMMODITIES INC 16,616 0.02 15 12428 NEW NGC, INC. 16,418 0.02 16 7411 DAVIS WIRE CORP 16,090 0.02 17 83102 LIGHT METALS INC 15,731 0.02 18 54402 SIERRA ALUMINUM COMPANY 15,677 0.02 19 117785 BALL METAL BEVERAGE CONTAINER CORP. 15,323 0.02 20 117290 B BRAUN MEDICAL, INC 15,167 0.02 21 151532 LINN OPERATING, INC 15,146 0.02 22 800408 NORTHROP GRUMMAN SYSTEMS 14,835 0.02 23 52517 REXAM BEVERAGE CAN COMPANY 14,827 0.02

### 215 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

24 115172 RAYTHEON COMPANY 14,365 0.02 25 21887 KIMBERLY-CLARK WORLDWIDE INC.-FULT. MILL 14,070 0.02 26 800088 3M COMPANY 13,446 0.02 27 800113 ROHR, INC. 12,593 0.02 28 115563 NCI GROUP INC., DBA, METAL COATERS OF CA 12,471 0.02 29 115314 LONG BEACH PEAKERS LLC 12,363 0.02 30 1073 BORAL ROOFING LLC 12,063 0.02 31 23752 AEROCRAFT HEAT TREATING CO INC 11,919 0.02 32 45746 PABCO BLDG PRODUCTS LLC,PABCO PAPER, DBA 11,885 0.02 33 3029 MATCHMASTER DYEING & FINISHING INC 11,691 0.02 34 127299 WILDFLOWER ENERGY LP/INDIGO GEN., LLC 11,529 0.02 35 43201 SNOW SUMMIT INC 11,028 0.02 36 800066 HITCO CARBON COMPOSITES INC 10,783 0.01 37 115315 GEN ON WEST, LP 10,625 0.01 38 61962 LA CITY, HARBOR DEPT 10,436 0.01 39 9053 VEOLIA ENERGY LOS ANGELES, INC 10,120 0.01 40 53729 TREND OFFSET PRINTING SERVICES, INC 10,005 0.01 41 97081 THE TERMO COMPANY 9,943 0.01 42 85943 SIERRA ALUMINUM COMPANY 9,856 0.01 43 22364 ITT CORPORATION 9,853 0.01 44 45471 O N I S, DBA, CARMEUSE INDUSTRIAL SANDS 9,784 0.01 45 800393 VALERO WILMINGTON ASPHALT PLANT 9,556 0.01 46 16978 CLOUGHERTY PACKING LLC/HORMEL FOODS CORP 9,424 0.01 47 61722 RICOH ELECTRONICS INC 9,200 0.01 48 22607 CALIFORNIA DAIRIES, INC 9,148 0.01 49 115241 BOEING SATELLITE SYSTEMS INC 9,142 0.01 50 101977 SIGNAL HILL PETROLEUM INC 8,791 0.01 51 131732 NEWPORT FAB, LLC 8,769 0.01 52 21598 ANGELICA TEXTILE SERVICES 8,675 0.01 53 139796 CITY OF RIVERSIDE PUBLIC UTILITIES DEPT 8,579 0.01 54 123774 HERAEUS PRECIOUS METALS NO. AMERICA, LLC 8,552 0.01 55 16737 ATKINSON BRICK CO 8,448 0.01 56 145836 AMERICAN APPAREL DYEING & FINISHING, INC 8,416 0.01 57 130211 PAPER-PAK INDUSTRIES 8,385 0.01 58 132068 BIMBO BAKERIES USA INC 8,379 0.01 59 800372 EQUILON ENTER. LLC, SHELL OIL PROD. US 8,284 0.01 60 157359 HENKEL ELECTRONIC MATERIALS, LLC 7,990 0.01 61 800196 AMERICAN AIRLINES INC (EIS USE) 7,985 0.01 62 115130 VERTIS, INC 7,890 0.01 63 37603 SGL TECHNIC INC, POLYCARBON DIVISION 7,638 0.01 64 19390 SULLY-MILLER CONTRACTING CO. 7,459 0.01 65 38872 MARS PETCARE U.S., INC. 7,248 0.01 66 131850 SHAW DIVERSIFIED SERVICES INC 7,207 0.01 67 3721 DART CONTAINER CORP OF CALIFORNIA 7,078 0.01 68 107656 CALMAT CO 7,014 0.01

### 216 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

69 56940 CITY OF ANAHEIM/COMB TURBINE GEN STATION 7,004 0.01 70 2825 MCP FOODS INC 6,991 0.01 71 800150 US GOVT, AF DEPT, MARCH AIR RESERVE BASE 6,892 0.01 72 11119 THE GAS CO./ SEMPRA ENERGY 6,820 0.01 73 152501 PRECISION SPECIALTY METALS, INC. 6,773 0.01 74 2912 HOLLIDAY ROCK CO INC 6,761 0.01 75 59618 PACIFIC CONTINENTAL TEXTILES, INC. 6,659 0.01 76 19167 R J NOBLE COMPANY 6,626 0.01 77 40034 BENTLEY PRINCE STREET INC 6,205 0.01 78 25638 BURBANK CITY, BURBANK WATER & POWER 6,137 0.01 79 800038 THE BOEING COMPANY - C17 PROGRAM 6,092 0.01 80 18455 ROYALTY CARPET MILLS INC 5,997 0.01 81 138568 CALIFORNIA DROP FORGE, INC 5,977 0.01 82 114997 RAYTHEON COMPANY 5,819 0.01 83 153199 THE KROGER CO/RALPHS GROCERY CO 5,639 0.01 84 161300 SAPA EXTRUDER, INC 5,600 0.01 85 96587 TEXOLLINI INC 5,573 0.01 86 165192 TRIUMPH AEROSTRUCTURES, LLC 5,464 0.01 87 115277 LAFAYETTE TEXTILE IND LLC 5,409 0.01 88 74424 ANGELICA TEXTILE SERVICES 5,347 0.01 89 137471 GRIFOLS BIOLOGICALS INC 5,246 0.01 90 153033 GEORGIA-PACIFIC CORRUGATED LLC 5,223 0.01 91 12155 ARMSTRONG WORLD INDUSTRIES INC 5,032 0.01 92 73022 US AIRWAYS INC 4,988 0.01 93 107654 CALMAT CO 4,897 0.01 94 156722 AMERICAN APPAREL KNIT AND DYE 4,841 0.01 95 11034 VEOLIA ENERGY LOS ANGELES, INC 4,831 0.01 96 800003 HONEYWELL INTERNATIONAL INC 4,826 0.01 97 141295 LEKOS DYE AND FINISHING, INC 4,686 0.01 98 124619 ARDAGH METAL PACKAGING USA INC. 4,543 0.01 99 155221 SAVE THE QUEEN LLC (DBA QUEEN MARY) 4,224 0.01 100 1744 KIRKHILL - TA COMPANY 4,003 0.01 101 11716 FONTANA PAPER MILLS INC 3,971 0.01 102 800417 PLAINS WEST COAST TERMINALS LLC 3,963 0.01 103 133987 PLAINS EXPLORATION & PRODUCTION CO, LP 3,883 0.01 104 143741 DCOR LLC 3,850 0.01 105 800149 US BORAX INC 3,825 0.01 106 63180 DARLING INTERNATIONAL INC 3,659 0.01 107 148925 CHERRY AEROSPACE 3,634 0.00 108 20604 RALPHS GROCERY CO 3,629 0.00 109 800094 EXXONMOBIL OIL CORPORATION 3,545 0.00 110 20203 RECYCLE TO CONSERVE INC. 3,542 0.00

### 217 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

110 20203 RECYCLE TO CONSERVE INC. 3,542 0.00 111 800067 BOEING SATELLITE SYSTEMS INC 3,409 0.00 112 117140 AOC, LLC 3,247 0.00 113 167066 ARLON GRAPHICS L.L.C. 3,239 0.00 114 5998 ALL AMERICAN ASPHALT 3,235 0.00 115 114264 ALL AMERICAN ASPHALT 3,233 0.00 116 15544 REICHHOLD INC 3,189 0.00 117 800338 SPECIALTY PAPER MILLS INC 3,097 0.00 118 800431 PRATT & WHITNEY ROCKETDYNE, INC. 3,028 0.00 119 17956 WESTERN METAL DECORATING CO 3,023 0.00 120 2946 PACIFIC FORGE INC 2,938 0.00 121 113160 HILTON COSTA MESA 2,936 0.00 122 42630 PRAXAIR INC 2,737 0.00 123 157363 INTERNATIONAL PAPER CO 2,661 0.00 124 107653 CALMAT CO 2,577 0.00 125 17623 LOS ANGELES ATHLETIC CLUB 2,511 0.00 126 50098 D&D DISPOSAL INC,WEST COAST RENDERING CO 2,501 0.00 127 98159 PACIFIC COAST ENERGY COMPANY LP 2,384 0.00 128 125015 LOS ANGELES TIMES COMMUNICATIONS LLC 2,339 0.00 129 95212 FABRICA 2,296 0.00 130 14871 SONOCO PRODUCTS CO 2,291 0.00 131 3968 TABC, INC 2,283 0.00 132 156741 HARBOR COGENERATION CO, LLC 2,277 0.00 133 124808 INEOS POLYPROPYLENE LLC 2,247 0.00 134 112853 NP COGEN INC 2,206 0.00 135 107655 CALMAT CO 2,182 0.00 136 2418 FRUIT GROWERS SUPPLY CO 2,083 0.00 137 94930 CARGILL INC 2,032 0.00 138 133813 EI COLTON, LLC 1,965 0.00 139 14049 MARUCHAN INC 1,949 0.00 140 168088 PCCR USA 1,903 0.00 141 800325 TIDELANDS OIL PRODUCTION CO 1,872 0.00 142 25058 EXXONMOBIL OIL CORP 1,787 0.00 143 800127 SO CAL GAS CO (EIS USE) 1,778 0.00 144 143740 DCOR LLC 1,741 0.00 145 105277 SULLY MILLER CONTRACTING CO 1,740 0.00 146 800181 CALIFORNIA PORTLAND CEMENT CO (NSR USE) 1,727 0.00 147 10094 ATLAS CARPET MILLS INC 1,726 0.00 148 117227 SHCI SM BCH HOTEL LLC, LOEWS SM BCH HOTE 1,724 0.00 149 158950 WINDSOR QUALITY FOOD CO. LTD. 1,701 0.00 150 800420 PLAINS WEST COAST TERMINALS LLC 1,690 0.00 151 42775 WEST NEWPORT OIL CO 1,661 0.00 152 143738 DCOR LLC 1,570 0.00 153 144455 LIFOAM INDUSTRIES, LLC 1,497 0.00 154 164204 CITY OF RIVERSIDE, PUBLIC UTILITIES DEPT 1,476 0.00

### 218 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

155 14736 THE BOEING COMPANY 1,458 0.00 156 169754 OXY USA INC 1,438 0.00 157 800416 PLAINS WEST COAST TERMINALS LLC 1,426 0.00 158 800110 THE BOEING COMPANY 1,369 0.00 159 800371 RAYTHEON SYSTEMS COMPANY - FULLERTON OPS 1,302 0.00 160 111415 VAN CAN COMPANY 1,268 0.00 161 115041 RAYTHEON COMPANY 1,188 0.00 162 800210 CONEXANT SYSTEMS INC 1,166 0.00 163 132071 DEAN FOODS CO. OF CALIFORNIA 1,164 0.00 164 151594 OXY USA, INC 1,132 0.00 165 5814 GAINEY CERAMICS INC 1,126 0.00 166 7416 PRAXAIR INC 1,108 0.00 167 124723 GREKA OIL & GAS, INC 1,025 0.00 168 17344 EXXONMOBIL OIL CORP 977 0.00 169 148340 THE BOEING CO. COMMERCIAL AVIATION SRVCS 950 0.00 170 14926 SEMPRA ENERGY (THE GAS CO) 948 0.00 171 89248 OLD COUNTRY MILLWORK INC 930 0.00 172 129810 CITY OF RIVERSIDE PUBLIC UTILITIES DEPT 866 0.00 173 800205 BANK OF AMERICA NT & SA, BREA CENTER 859 0.00 174 132191 PURENERGY OPERATING SERVICES, LLC 826 0.00 175 68118 TIDELANDS OIL PRODUCTION COMPANY ETAL 823 0.00 176 12372 MISSION CLAY PRODUCTS 787 0.00 177 16660 THE BOEING COMPANY 761 0.00 178 142267 FS PRECISION TECH LLC 739 0.00 179 47771 DELEO CLAY TILE CO INC 657 0.00 180 151899 VINTAGE PRODUCTION CALIFORNIA LLC 645 0.00 181 133996 PLAINS EXPLORATION & PRODUCTION COMPANY 611 0.00 182 14944 CENTRAL WIRE, INC. 564 0.00 183 800264 EDGINGTON OIL COMPANY 481 0.00 184 800182 RIVERSIDE CEMENT CO (EIS USE) 456 0.00 185 800344 CALIFORNIA AIR NATIONAL GUARD, MARCH AFB 425 0.00 186 40483 NELCO PROD. INC 282 0.00 187 160888 HINES REIT EL SEGUNDO, LP 271 0.00 188 125579 DIRECTV 268 0.00 189 9217 VEOLIA ENERGY LOS ANGELES, INC 220 0.00 190 14502 VERNON CITY, LIGHT & POWER DEPT 172 0.00 191 137508 TONOGA INC, TACONIC DBA 93 0.00 192 143739 DCOR LLC 79 0.00 193 2083 SUPERIOR INDUSTRIES INTERNATIONAL INC 75 0.00 194 142536 DRS SENSORS & TARGETING SYSTEMS, INC 72 0.00 195 149491 BOEING REALTY CORP 49 0.00 196 132192 PURENERGY OPERATING SERVICES, LLC 29 0.00 197 800373 CENCO REFINING COMPANY 25 0.00 198 12185 US GYPSUM CO 5 0.00

### 219 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

199 141555 CASTAIC CLAY PRODUCTS, LLC 4 0.00 200 151394 LINN WESTERN OPERATING INC 4 0.00 201 152054 LINN WESTERN OPERATING INC 3 0.00 202 58622 LOS ANGELES COLD STORAGE CO 1 0.00 203 151415 LINN WESTERN OPERATING, INC 1 0.00 204 1634 STEELCASE INC, WESTERN DIV 0 0.00 205 15164 HIGGINS BRICK CO 0 0.00 206 20543 REDCO II 0 0.00 207 23196 SUNKIST GROWERS, INC 0 0.00 208 38440 COOPER & BRAIN - BREA 0 0.00 209 42676 CES PLACERITA INC 0 0.00 210 119104 CALMAT CO 0 0.00 211 137520 PLAINS WEST COAST TERMINALS LLC 0 0.00 212 146536 WALNUT CREEK ENERGY, LLC 0 0.00 213 148896 VINTAGE PRODUCTION CALIFORNIA LLC 0 0.00 214 148897 VINTAGE PRODUCTION CALIFORNIA LLC 0 0.00 215 151601 OXY USA, INC. 0 0.00 216 152707 CPV SENTINEL LLC 0 0.00 217 152857 GEORGIA-PACIFIC GYPSUM LLC 0 0.00 218 800343 BOEING SATELLITE SYSTEMS, INC 0 0.00 219 800419 PLAINS WEST COAST TERMINALS LLC 0 0.00 TOTAL (281 Facilities by end of June 2011) 20.006 Note: August 29, 2013 data from RECLAIM Admin team

### 220 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix W – 2012 Emission s for Power Electricity Generating Sector

The base year for the BARCT analysis is compliance year 2011. However, the 2011 base year would not be appropriate for this source catego ry due to the uniqueness of its operations. There have been several changes within recent years th at have warranted the use of more recent base year data. The San Onofre Nuclear Generating Station (SON GS) has not been in operation since early 2012 and is now undergoing decommissioning. The power deficit was to be madeup by other natural gas fired units in the region. Other existing units are subject to the once-through-cooling (OTC) regulation and will have to be repowered. These repowered units are predicted to be more efficient units that consume less natural gas to produce th e same amount of power as their predecessors. Other trends in the industry have begun to affectpower availability such as the increased use of renewable power, like wind, water, and solar. The state of California must meet a 33% Renewable Portfolio Standard by 2020, and the inherent vol atility of these renewable energy sources means that gas demand must be met almost in real time. The growth factor for electri cal electricity generating facilities came from the 2012 California Gas Report, consistent with what is used for the AQMP projections for these facilities. However, Bbased on the 2014 California Gas Report, gas demand inthe future is set to decrease slightly due to the utilization of more effi cient electrical electrici ty generating facilities, greenhouse gas (GHG) reductions, and the increased use of renewable power. The projected emissions in 2023 using compliance year 2011 as the base year used gr owth factors from SCAG (Southern California Association of Governments) for non-el ectrical electricity generating facilities.
Table W. 1 - Compliance Year 2011 Power Electricity Generating Sector Emissions Compliance Year 2011 Emissions (tpd) 2011 Emissions at BARCT/BACT (tpd) Growth Factor 2023 Emissions with Growth (tpd) 1.45 2.57 1.146 2.95 The figures above included those electrical electricity generating facilities among the top 37 NOx emitters in compliance year 2011. An additional 0.34 tons per day came from electrical electricity generating facilities outside the top 37 and was included as part of the “Other Sources” category with a different growth factor. More recent base year data was obtained using calendar year AER (Annual Emissions Report) fuel usage data for 2012. The calendar year 2012 emissi ons include those for the major sources only

### 221 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 belonging to electric generating facility source category (includes boilers, gas turbines, and ICEs). The emissions from process units and any Rule 219 equipment are almost negligible (the emissions from process units in 2011 were 0.006 tpd).

Table W. 2 - 2012 Power Electricity Generating Sector Emi ssions Based on Annual Emission Reports (AER) Fuel Usage

Calendar Year 2012 Emissions (tpd) 2012 Emissions at BARCT/BACT (tpd) Growth Factor 2023 Emissions with Growth (tpd) 2.50 2.35 0.8683 2.04
The growth factor was extrapolated from the ta bles in the 2104 2014 California Gas Report and it shows a slight decrease in demand for natural ga s. There were nine electrical electricity generating facilities among the top 37 emitters in compliance year 2011. For this updated analysis, all electrical electricity generating facilities in RECLAIM were included (30 in total) and their emissions at the BARCT or BACT level were calculated. Most of the units are already meeting BARCT or BACT requirements, due to previous rule requirements. Another unique aspect of the power electricityl generating sector is that many of the newer units are subject to new source review (NSR) holding requirements. Pe r Rule 2005, if a facility is new (received all its District permits on or after October 15, 1993), it must hold sufficient RTCs in advance of every year at the equipment’s potential to emit level. Virtually all power generating units typically operate at a level far below its potential to emit, but the facility must still hold the RTCs to comply with the NSR demonstration. Stakeholders have brou ght to SCAQMD staff’s attention their concern about the shave and whet her a power generating facility can still comply with its emission allocation and NS R demonstration concurrently, especially when there is no cost effective method to retrofit thei r equipment to generate credits. SCAQMD staff has proposed a safety valve for a ddressing the concerns of the power electricity generating sector. A Regional NSR Holding A ccount has been proposed that would consist of RTCs solely to meet the programmatic NSR hol ding demonstration. Under this approach, individual facility holding requirements would no longer be necessary. Concerns have also been raised in the event that a power emergency is ex perienced and there is anadded demand for power production. SCAQMD staff has also proposed to allow access to the Regional NSR Holding Account if the Governor declar es a state of emergency.

### 222 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix X – Proposed Chan ges in Rules 2001, 2002, 2005, 2011 and 2012
Rule 2001
Staff is proposing that the owner or operator of an electricity generating facility (EGF) would have the option of having their facility or facilities exit from the NOx RECLAIM program. This opting out of NOx RECLAIM is contingent on the submittal of a plan application subject to plan fees specified in Rule 306. To request this opting- out of the NOx RECLAIM program the following requirements are must be met as demonstrated in an opt-out plan submitted to the Executive Officer: • At least 99 percent of the EGF’s NOx emissions for the most recent three full compliance years are from equipment that meets current Best Available Control Technology (BACT) or Best Available Retrofit Control Technology (BARCT), for NOx. • The EGF is subject to NOx RECLAIM as of the date of the amendment or has been subject to NOx RECLAIM for at least 10 years as of the plan submittal date. For the purposes of Rule 2001, an EGF is defined as a NOx RECLAIM facility that generates electricity for distribution in the state or local grid system. However, this type of facility would not include a cogeneration facility. That is, a facility that sequentially produces electricity and another form of useful thermal energy (such as heat or steam) in a way that is more efficient than the separate production of both forms of energy. Based on the timing that the EGF entered RECLAIM and as part of the opting-out procedures the EGF Facility Permit holder must submit applications to include in its permit and accept permit conditions that ensure all of the following apply:

• For an EGF s for which all permits were issued on or after January 1, 1994 that does not meet the definition of an existing facility, as defined in Rule 2000(c)(35), the quantity of NOx RTCs fo r all compliance years after the date of approval of the opt-out plan and required to be held by the facility pursuant to Rule 2005 – New Source Review for RECLAIM must be surrendered by the EGF, retired from the market, and usedto satisfy any NOx requirements for continuing obligations under Regulation XIII – New Source Review. If needed to equal this amount, any Non-tradab le/Non-usable RTCs and any RTCs

### 223 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 corresponding to the EGF’s contribution to the Regional NSR Holding Account may be used for this purpose and, if so used, would be removed from the Account. • For existing EGFs, an amount of NOx RTCs equivalent to the facility’s NOx holdings as of September 22, 2015 for a ll compliance years after the date of approval of the opt-out plan must be surrendered by the EGF, retired from the market. • Any NOx RTCs held by an EGF beyond those referred above may be sold, traded, or transferred used by the EGF. Other important requirements associated with EGFs opting-out of NOx RECLAIM include: That the EGF operator ensures that all equipment identified in the opt-out plan as meeting BACT or BARCT must not exceed at its respective BACT or BARCT levels of emissions or any existing permit condition limiting NOx emission that is lower than BACT or BARCT as of the date of the opt-out plan submittal. • Limits on EGF Emissions For existing EGFs, total facility emissions shall be limited to the amount of Compliance Year 2015 RTCs held as of September 22, 2015. The facility NOx emission limit shall be apportioned to each NOx source in the same proportion as its share of the EGF’s emissions during the three complete compliance years prior to the date of opt-out plan submittal.

x For existing EGFs the total facility emissions would be limited to the amount of Compliance Year 2015 RTCs held as of September 22, 2015.

x For an EGF that does not meet the definition of an existing facility emissions from each NOx source would be limited to the amount of RTCs required to be held for that source pursuant to Rule 2005 as of the date of opt-out plan submittal. The owner or operator of multiple EG Fs under common control would have one opportunity to apportion the NOx e mission limits among its facilities under common control, provided all of the facilities opt out concurrently. The apportionment must be described in the opt -out plan that shall be submitted to the Executive Officer. Each facility shall not have a limit that exceeds the amount of emissions that can be generate d by all existing equipment located at the facility. For EGFs for which all permits were issued on or after January 1, 1994, emissions from each NOx source mu st be limited to the amount of RTCs required to be held for that source pursu ant to Rule 2005 as of the date of the opt-out plan submittal.

### 224 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 • Subdivision (j) shall not be applicable to the EGF for any equipment installed or modified after the date of approva l of the opt-out plan, and for existing equipment at the earliest practicable date but no later than three years after the date of the approved opt-out plan. • The EGF operator must continue to co mply with the requirements of Rule 2012 – Requirements for Monitoring, Reportin g, and Recordkeeping for Oxides of Nitrogen (NOx) Emissions and its associated protocols unless the Executive Officer has approved an alternative mon itoring and recordkeeping plan which is sufficient to determine compliance with all applicable rules. o.• For EGFs not subject to Regulation XXX – Title V Permits, the EGF’s permit must be re-designated as an “opt-out facility permit” and shall remain in effect, subject to annual renewal, unless expi red, revoked, or modified pursuant to applicable rules. The EGF operator must continue to pay RECLAIM permit fees pursuant to Rule 301(l). After an EGF is removed out of NOx RECLAIM, Regulations XI and XIII would apply. The Executive Officer would approve or deny the opt-out plan within 180 days of receipt of a complete plan, unless the EGF and the Executive O fficer have mutually agreed upon a longer time period. The Executive Officer will not approve the opt -out plan unless it has been determined that the abovementioned requirements are met (also see subparagraphs (g)(1)( A) and (g)(1)(B)) and the EGF accepts appropriate permit conditions toensure proper compliance as specified above (also see subparagraphs (g)(2)(B) through ( G H)). If, within 180 days or within the mutually agreed upon time period of receiving a complete op t-out plan, the Executive Officer does not take action on it, the EGF may consider it denied and petition the Hearing Board. The Executive Officer shall not re-issue the facility permit removing the EGF from RECLAIM unless the EGF surrendered the required amount of RTCs pursuant to subparagraph (g)(2)(A). Removal from RECLAIM of an EGF with an approved opt-out planis effective upon issuance of a facility permit incorporating the conditions mentione d above (also see paragraph (g)(2)). As currently specified no facility, on the initial Facility Listing or subsequently admitted to RECLAIM, may opt out of the program, unless approved by the Executive Officer according to above described requirements associated with an EGF. The EGF option of exiting from the NOx RECLAIM program is also mentioned as one of the several exemptions in 2001(i)(1) and (2).

### 225 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Rule 2002
The purpose of Rule 2002 is to establish the methodology for calculating facility Allocations and adjustments to RTC holdings for Oxides of N itrogen (NOx) and Oxides of Sulfur (SOx). Rule 2002 provides an overview of the RECLAIM A llocations; the establishment of starting, year 2000 and 2003 Allocations, the annual Allocations for NOx and SOx and the adjustments to RTC holdings. Rule 2002 also specifies the require ment for establishing High Employment/Low Emissions (HILO) facilities, Non-Tradable A llocation Credits, and RTC Reduction Exemptions. In addition to these sections of the rule there are various tables specifying RECLAIM equipment emission factors and the identification of certain facilities status with regards to the RECLAIM Allocation adjustment. The most substantive proposed rule am endments are found in subdivision (f) Annual Allocations for NOx and SOx and Adjustments to RTC Holdings as well as the additions of Table 7 - List of NOx RECLAIM Facilities Referenced in Subparagraph (f)(1)(B) , Table 8 - List of NOx RECLAIM Facilities Referenced in Subparagraph (f)(1)(C) , and Table 9 - List of NOx RECLAIM Facilities for the Regional NSR Holding Account with Balances (in lbs). Staff isOther important proposed changes include updated and new RTC price thres hold values removal of the also proposing to remove subdivision (i) RTC Reduction Exemption , and added a new requirement for facility and equipment shutdowns from the Rule 2002

. The staff proposal calls for a programmatic reduction of 14 tons per day. Four tons per day would be reduced in 2016 and the remainder would be redu ced in equal increments of 2 tons per day from 2018 to 2022. There would be no reductions propos ed for the year 2017. These reductions are reflected in subparagraphs (f)(1)(B) and (f)(1)(C). Subparagraph (f)(1)(B) includes all of Major Refineries and Investors. The Major Refineries are listed in Table 7 of Rule 2002. Subparagraph (f)(1)(C) includes all other facilities subject to reductions in NOx RTCs. These facilities are listed in Table 8 of Rule 2002. These adjustment factors would also apply to subsequent owners of any of these facilities. Thus the remaining NOx RTCs after a shave for any compliance year would be the Tradable/Usable NOx RTC Adjustment factor in(f)(1)(B) multiplied by the RTC holdings (as of September 22, 2015) of all the Major Refineries and Investors listed in Table 7 plus the Tradable/Usable NOx RTC Adjustment factor in(f)(1)(C) multiplied by the RTC holdings (as of September 22, 2015) of all the fac ilities listed in Table 8. For purposes of assigning the appropriate adjustment factor(s) for any RTC sold by an RTC holder that both purchased and sold RTCs between September 22, 2015 and the date of amendment will be based on a last in/first out basis. at the time each transaction was registered.

### 226 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Since the RTC reductions specified in subparagraph (f)(1)(A) have been realized the conversion of non-tradable/non-usable NOx RTCs to tradable/usable NOx RTCs is no longer applicable to the RTC reductions specified in this subparagrap h. The tradable/usable NOx RTCs specified in subparagraph (f)(1)(A) would remain intact and used for calculating RTC reductions for facilities entering the RECLAIM program. However, a similar approach in applying adjustment factors previously specified in subparagraph (f)(1)(A) would now be applied to the RTC reductions specified in subparagraphs (f)(1)(B) and (f)(1)(C). Many of the proposed amendments to Rule 2002 focu s on what will be done to provide access to RTCs to affected electrical electricity generating facilities (EGF) in the RECLAIM program under a State of Emergency related to electricity demand or power grid stability in the Basinwithin the SCAQMD jurisdictional boundaries. Other ame ndments focus on providing relief from burdensome New Source Review (NSR) holding requirement for newer electrical electricity generating facilities that en tered RECLAIM after 1993. New electrical generating facilities EGFs must hold sufficient RTCs to offset emission increases for one year prior to commencement of operation and at the beginning of every compliance year thereafter. These requirements are triggered in cases where a facility incurs an emission increase as defined under Rule 2005(d) – Emission Increase. Staff has identified ten (10) new electrical electricity generating facilities subject to this requirement. These facilities are listed in Table 9 of Rule 2002. Staff is providing in Table 9 the qua ntity of NOx RTCs commensurate to the shave amount for these ten new electrical electricity generating facilities. These RTCs would be placed in a Regional NSR Holding Account as per subp aragraph (f)(1)(GF) for the specific purpose of helping to comply with the requirements specified in Rule 2005. According to subparagraph (f)(1)(F), at the conclusion of any of the compliance years 2016 through 2022 if the NOx RTC pri ces have not exceeded the propos ed $22,500 per ton threshold as specified in subparagraph (f)(1)(I) and a State of Emergency relate d to electricity demand or power grid stability in the Basin as specified in paragr aph (f)(4) has not been declared by the Governor, then the Non-tradable/Non-usable NOx RTCs fo r that compliance year, except for those RTCs specified in subparagraph (f)(1)(G), shall be sub mitted as part of the State Implementation Plan commitment. According to subparagraph (f)(1)(GF) the Executive Officer will transfer to a Regional NSR Holding account the amount of NOx RT Cs holdings listed in Table 9 of this Rule from the corresponding facilities id entified in the same table.. The threshold of $15,000 per ton has been updated to $22,500 per ton, consistent with the costeffectiveness threshold for additional analysis in the 2012 AQMP. ( 2012 AQMP, Chapter 4: Control Strategy and Implementation, page 4-43 )

### 227 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 A companion provision to the abovementioned su bparagraphs is subparagraph (f)(1)(HG) which states that for the purposes of m eeting the NSR holding requirement as specified in subdivision (f) of Rule 2005, the facilities identifie d in Table 9 may use a combination of their Tradable/Usable and Non-tradable/Non-usable RTCs specified insubparagraph (f)(1)(C) and the amount for each facility listed in Table 9 whic h represent the RTCs in the Regional NSR Holding account. Other than the updated price trigger, other propos ed changes to subparagraph (f)(1)(I) require the Executive Officer to include in his report to th e Governing Board a commitment and schedule to conduct a more rigorous analysis of the RECLAIM program. The deletion of subparagraphs (f)(1)(D), (f)(1)(E), and (f)(1)(F) [existing rule designation] and proposed changes to subparagraphs (f)(1)(KL) an d (f)(1)(LM) reflect the change from using the adjustment factors in (f)(1)(A) [previous NOx RECLAIM amendment] to the adjustment factors applied in this proposed amendment, as well as updated methods for dete rmining allocations for existing facilities that enter RECLAIM. Staff is proposing to add RTC price threshol ds based on a 3-month averaging period and a minimum RTC price threshold based on a 12-month averaging period. As previously mentioned the current RTC price threshold based on a 12-m onth averaging period is proposed to be changed from $15,000 to $22,500 per ton.
With regards to the proposed 3-month averaging period staff will calculate the 3-month rolling average RTC price for all trades for the current compliance year. This running assessment will commence on May 1, 2016 with the NOx RTC prices averaged from January 1, 2016 through March 31, 2016. As with the 12-month rolling averag e staff will update the 3-month and once per month. [subparagraph (f)(1)(E)] Notwithstanding the requirements of non-tradabl e/non-usable credits specified in subparagraphs (f)(1)(A), iIn the event that the NOx RTC prices exceed $15,000$22,500 per ton ( discrete current compliance year credits) based on the 12-month rolling average, or exceed $35,000 per ton ( discrete current compliance year credits) based on the 3-month rolling average calculated pursuant to subparagraph (f)(1)(BE), the ExecutiveOfficer will report th e determination to the Governing Board. If the Governing Board finds that the 12-month rolling average RTC price exceeds $15,000$22,500 per ton or the 3-month rolling average RTC price exceeds $35,000 per ton, then the incremental Non-tradable/Non-usab le NOx reductions RTCs, as specified in subparagraphs (f)(1)(DB) and (f)(1)(C) valid for th e period in which the RTC price is found to have exceeded the applicable threshold, compliance year in which Cycle 1 facilities are currently operating shall be converted to Tradable/Usable NOx RTCs upon Governing Board concurrence. According to subparagraph (f)(1)(JF), in the event that the NOx RTC prices fall below $200,000 per ton (infinite year block) based on the 12-month rolling average staff will report the

### 228 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 determination to the Governing Board. For the purpos e of this rule, infinite year block refers to trades involving blocks of RTCs with a specified start year and continuing into the future for ten or more years. In the event that the infinite year block NOx RTC prices fall below $200,000 per ton based on the 12-month rolling average, calculated pursuant to subparagraph (f)(1)(E) beginning in 2019 for the compliance year in which Cycle 1 facilities are operating, the Executive Officer will report the determination to the Governing Board. For the purpose of this rule, infinite year block re fers to trades involving blocks of RTCs with a specified start year and continuing into the future for ten or more years. The addition of paragraph (f)(4) describes provisi ons to convert Non-tr adable/Non-usable RTCS s and the Regional NSR Holding Account during a St ate of Emergency declared by the Governor related to electricity demand or power grid stability within the SCAQMD jurisdictional boundariesin the Basin. Specifically, such as a St ate of Emergency, the current compliance year Non-tradable/Non-usable NOx RTCs held by an y electricityal generating facilities that generate and distribute electricity to the grid system affected by the State of Emergency may be used to offset emissions after completely exhaus ting their own Tradable/Usable NOx RTCs. If such a facility has completely exhausted their Non-tradable/Non-usable NOx RTCs, the owner or operator of the facility may apply for the use of the NOx RTCs in the Regional NSR Holding Account. The use of such RTCs in this Account would be based on availability at the end of each quarter. The owner or operator of each electri cal electricity generating facility requesting NOx RTCs from the Regional NSR Holding Account w ould be required to submit a written request to the Executive Officer specifying the amount of RT Cs needed and the basis for requesting the required amount.

The Executive Officer will determine the amount and distribution of the NOx RTCs from the Regional NSR Holding Account ba sed on the requesting facility meeting the following criteria:
(i) The State of Emergency related to electricity demand or power grid stability within the SCAQMD jurisdictional boundariesin the Ba sin, as declared by the Governor, was the direct cause of the excess emissions. (ii) The facility has been ordered to generateelectricity in an in creased amount and/or frequency due to the State of Emergency. (iii) The facility has adequately demonstrated their need for the specific amount of RTCs from the Regional NSR Holding Account.

### 229 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
(iv) The facility owner or operator has not sold any part of their RTC holdings for the subject compliance year. If the total RTCs requested exceed the supply of RTCs in this Account, the RTCs will be distributed proportionately according to the offset needs of the facilities on a quarterly basis. These RTCs will be non-tradable, but usable to offset emissions.
According to paragraph (f)(5) the Executive Officer will report to the Governing Board within 60 days of the end of the quarter in which the State of Emergency was declareddeclaration by the Governor related to electricity demand or power grid stability within the SCAQMD jurisdictional boundariesin the Basin. Included in th is report will be, as applicable:
(i) the quantity of RTCs from the Regional NSR Holding Account that were distributed for compliance w ith the requirement to rec oncile quarterly and annual emissions; (ii) any adverse impacts that the State of Emergency is having on the RECLAIM program; and (iii) any potential changes to the RECLAIM program that will be needed to help correct these impacts.

There has also been some changes to paragraph (f)(1)(LM) that pertain to NOx Allocations for existing facilities that enter RECLAI M after the date of adoption. For this rule provision for Compliance Year 2016 and all subsequent years th e amount determined pursuant to subparagraph (d)(1)(A) except the variable B2 shall be the lowest of: (i) The applicable 2000 (Tier I) Ending Emis sion Factor for the subject source(s) or process unit(s), as specified in Table 1 multiplied by the percentage inventory adjustment pursuant to subdivision (e) (0.72); (ii) The BARCT Emission factor for the subj ect source as specified in Table 3; and (iii) The proposed BARCT Emission factor fo r the subject as specified in Table 6. For those facilities that are permanently shutti ng down, staff is proposing that their NOx RTCs will be retired from the NOx Program. To that end starting on the date of amendment it is proposed that the highest ranking official of any facility selling any infinite year block (IYB) RTCs must provide the Executive Officer a

### 230 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 written statement that there is no intention to shut down the facility. For the purpose of this rule, IYB refer to trades involving blocks of RTCs witha specified start year and continuing into the future for ten or more years. This will provide staff assurance that the trade in question is not related to a permanent shutdown. It is proposed that any Facility Permit Holder of a facility listed in Table 7 or 8 in Rule 2002 that is permanently shutting down some or all equipment with emissions greater than or equal to 25 percent of the facility emissions for any quarter within the previous 2 compliance years must surrender: NOx RTCs to the District for retirement from the RECLAIM Program; and the permit(s) for the equipment that is shutdown. Starting ( date of amendment) the highest ranking official of any facility listed in Table 7 or 8 selling any infinite year block (IYB) RTCs shall provide the Executive Officer a written statement that there is no current intent ion to shut down the facility within the next five years. For the purpose of this rule, IYB refer to trades involving blocks of RTCs with a specified start year and continuing into the future for ten or more years.
On or after [ 2 years after date of amendment], A any Facility Permit Holder of a facility listed in Table 7 or 8 permanently shutting down some or all one or more pieces of equipment with emissions greater than or equal to 25 percent of the facility’s total NOx emissions for any quarter within the previous 2 compliance years shall surrender: (A) NOx RTCs as determined under paragraph (i )(3) to the District for retirement from the RECLAIM Program; and (B) the permit(s) for the equipment that is shutdown. It should be noted that equipment will be deemedshut down and subject to the RTC and permit surrender requirements if it is non-operational for a period of tw o consecutive years or longer, unless the subject equipment is used in a cyclical operation with a cyclic period of two or more years. The reasons for non-operation cannot be attributed to ec onomic circumstances. The NOx RTCs to be surrendered must include those valid for all compliance years starting from the compliance year after the shutdown occurs and be equal to the NOx Allocations issued by the District to the facility multiplied by the maximum quarterly ratio in the previous 2 years. For the purposes of this rule, each quarterly ratio shall be calculated as follows: ݋݅ݐܴܽ ݕ݈ݎ݁ݐݎܽݑܳ ݐ݉݁݊݌݅ݑݍ݁ ݊ݓ݋݀ݐݑ݄ݏ ݄݁ݐ ݉݋ݎ݂ ݏ݊݋݅ݏݏ݁݉݅ ݔܱܰ ݕ݈ݎ݁ݐݎܽݑܳ = ݎ݁ݐݎܽݑݍ ܽ݉݁ݏ ݄݁ݐ ݎ݋݂ ݏ݊݋݅ݏݏ݁݉݅ ݔܱܰ ݕ݈ݎ݁ݐݎܽݑݍ ݂݅݅݁݀ݐݎܿ݁ ݕݐ݂݈ܽܿ݅݅ ݈ܽݐ݋ܶ

### 231 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The requirements related to th e abovementioned fac ility and equipment shutdowns would not apply to shutdown equipment for which the equipm ent’s operational capacity is replaced by new or existing equipment serving the same functional needs at the same facility or another facility under common control. Notwithstanding the requirements of Rule 204, the Executive Officer shall notify the Facility Permit Holder 60 days prior to re-issuing the F acility Permit to reflect removal of the shutdown equipment from the Facility Permit.



## Rule 2005

Rule 2005 sets forth requirements for new or modified equipment or processes at RECLAIM facilities. The purpose of the rule is to ensure that the RECLAIM program is equivalent to the federal and state NSR program re quirements. Rule 2005 provides three separate requirements to meet the NSR programmatic equivalency: 1) Sources causing emission increases must be equipped with Best Available Control Technology (BACT), 2) Modeling must be used to demonstrate that operation of the source will not result in a significant increase in the air quality concentration of nitrogen dioxide (NO ) if the facility 2 total emissions exceed its 1994 starting allo cations plus non-tradable credits, and 3) The facility must hold sufficient RTCs to offset emission increases for one year prior to commencement of operation and at the beginning of every compliance year thereafter. These requirements are triggered in cases where a facility incurs an emission increase as defined under Rule 2005(d) – Emission Increase. The ev aluation of emission increases under this paragraph is defined on a device-by-device basis at the maximum potential to emit. Any time a new NOx- (or SOx)-emitting RECLAIM device is installed, it triggers the credit holding requirements because it does not haveany prior emissions, even in cases where the new device is replacing an older, dirtier device. Among these requirements, the credit holding requirement ensures that the facility has adequate credits to offset emission increases year-by-year. It does not directly require emission decreases. On the other hand, all RECLAIM facilities are required to reconcile their Allocations to their emissions (i.e. hold enough RTCs to cover their emissions) by the end of each quarter and each

### 232 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 compliance year pursuant to Rule2004 – Requirements. Therefore, under RECLAIM, all facilities are required to have credits to offset all RECLAIM emissions regardless if they are subject to the requirements of Rule 2005. The amendments made in June 3, 2011 required anexisting RECLAIM facility to hold adequate RTCs for the first year of operation prior to co mmencement of operation of a new or modified source, but will not require the facility to hold RTCs at the commencement of subsequent compliance years, provided that the facility emission level remains below its starting Allocations plus non-tradable credits. The offset requirements for new RECLAIM facilities remained unchanged. Thus a new facility will have to continue to hold ad equate RTCs equal to the amount of emission increases at the beginning of each compliance year. Any unusedRTCs cannot be sold until the end of the compliance year, or the applicable quarters if the facility has permit conditions to cap its emissions during each quarter, thus allowing sale of unused RTCs at the end of the quarter. To help in remedying this holding requirement for new electrical electricity generating facilities that cannot change their allowable NOx emission s in their Facility Permit, staff is proposing a Regional NSR Holing Account in Rule 2002. Propos ed changes in Rule 2005 would assure that the Regional NSR Holing Account would be used the for the purpose of complying with the NSR requirements.


## Other Administrative Amendments

Besides the changes described in Rule 2002 and 2005 above, staff also proposes administrative amendments to Regulation XX to clarify the rule language and to ensure effective and consistent implementation of the RECLAIM program.
Rule 2002(b) - 5-Year Limitation on Amending Annual Emission Reports Rule 2002 – Allocations for Oxides of Nitrogen ( NOx) and Oxides of Sulfur (SOx) specifies the procedures for quantifying RECLAIM allocations for facilities in the original (1994) RECLAIM universe, facilities electing to enter the program, and facilities included into the program because they experienced actual NOx or SOx emissions of four tons or more in a year. Allocations are quantified by multiplyin g throughput levels ( e.g. , quantity of fuel consumed or of material processed) documented in peak year Annual Emission Reports (AERs), by emission factors specified in Rule 2002. However, if the emission factors used in preparing the peak year AER reports are lower than those in Rule 2002, then the lower factors are to be used for quantifying allocations.

### 233 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Some facilities entering the RECLAIM program have sought to amend their past AERs, which dated as far back as 1989, in ways that increasethe initial SOx and/or NOx allocations quantified for them pursuant to Rule 2002. The longer th e time elapsed between the reporting period and submittal of the correction the more problematic the process of validating the proposed corrections and their supporting documentation becomes. In fact , such validation has been infeasible in some cases. Therefore, staff is proposing to add paragraph (b)(5) to Rule 2002 specifying that the Executive Officer will not consider any AER data submitted five years beyond the original due date when calculating a facility’s allocation. This language would provide clarity to RECLAIM facilities and potential RECLAIM facilities regarding what AR submittals and/or revisions may be considered in determining their allocations, as well as relieve the costs, both financial and in terms of staff resources, associated with review and validation of AER submittals made long after the reporting periods for which they are submitted. Rule 2002 (Table 4) – Minor Typographical Edit

Rule 2002’s Table 4 – RECLAIM SOx Tier III E mission Standards includes a row for Diesel Combustion, which includes a BARCT Emission St andard of “15 ppmv as required under Rule 431.2.” However, the standard in Rule 431.2 is ac tually “15 ppm by weight” rather than 15 ppmv ( i.e. , 15 ppm by volume). The staff proposal would co rrect the Table 4 entry to “15 ppm by weight as required under Rule 431.2,” consistent with the definition of Low Sulfur Diesel at Rule 431.2(b)(5).
Rules 2011 and 2012 - Delayed RATA Tests du e to Extenuating Circumstances Rules 2011 – Requirements for Monitoring, Reportin g, and Recordkeeping for Oxides of Sulfur (SOx) Emissions and 2012 – Requirements for M onitoring, Reporting, and Recordkeeping for Oxides of Nitrogen (NOx) Emissions set fo rth monitoring, reporting, and recordkeeping requirements for sources of SOx and NOx at RECLAIM facilities. The accompanying Appendices A to these rules, Rule 2011 – Protocol for Monito ring, Reporting, and Recordkeeping for Oxides of Sulfur (SOx) Emissions and Rule 2012 – Protocol for Monitoring, Reporting, and Recordkeeping for Oxides of Nitrogen (NOx) Emissions, outline in greater detail the technical specifications required for monitoring, reporting, and recordkeeping for RECLAIM sources. Moreover, Attachment C, Subdivision B, Paragraph 2 of Appendix A of both these protocols, sets forth the timing and frequency of Semi-Annual Assessmen ts in the form of Relative Accuracy Test Audits (RATAs) for RECLAIM Continuous Emission Monitoring Systems (CEMS). For instance, SOx and NOx equipment monitored by CEMS ar e required to perform RATAs on a semi-annual basis within six months of the end of the calenda r quarter in which the CEMS last passed such a test. Such RATAs may be performed on an annual basis, provided that the relative accuracies of the SOx (NOx) pollutant concentration monitor, flow monitoring system, and the SOx (NOx)

### 234 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 emission rate measurement system measured durin g the previous audit are 7.5% or less. These stringent testing requirements help ensure the accuracy of the CEMS in monitoring SOx and NOx emissions.

RATAs are conducted while the e quipment is in operation. Equipment monitored by CEMS at some RECLAIM facilities, however, may experience extenuating circumstances that prevent them from conducting RATA tests in a timely manner. For instance, a major source may experience unforeseen equipment failure that renders it in operable. Under such unforeseen events, the equipment cannot be made operational to conduct a RATA. Additionally, facilities under contract with the California Independent System Operator (CalISO), as well as electrical electricity generating facilities owned and operated by municipalities, have experienced difficulties in meeting RATA deadlines because their equipment operates based on current energy demand and may not operate long enough (or at all) to conduct a RATA in the quarter in which the RATA is due. In contrast, most facilities typically require their major sources to be continually operational, used on a regular ba sis, and able to conduct a timely RATA for their equipment. In the event that their equipment is not in operation, the facility has the option of seeking a variance or filing an application for non- operational status to avoid violating the RATA requirement since sources permitted as non-operational are not required to conduct RATAs. However, electrical electricity generating facilities with equipment under contract with CalISO or owned and operated by municipalities often do not know when demand for electricity will result in generation equipment being required to operate until a day prior, creating scheduling difficulties in conducting RATAs and precluding the use of non-ope rational status. The i nherent inconsistent operational nature of such equipment at electric generating facilities sometimes causes a need to postpone their RATAs. Under current rule requirements, facilities having such extenuating circumstances seek variances for indeterminate amounts of time. The proposed amendments would, under specific conditions, allow RECLAIM Facility Permit Holders of equipment experiencing these extenuating circumstances to postpone RATAs. In the case of unforeseen equipment failure, Facility Permit Holders would have the option to postpone RATAs for this equipment to no more than 14 operating days after recommencing operation of the repaired equipment. Concerns we re expressed that 14 operating days may not be sufficient in cases of sequential failures of the same equipment. However, the proposed 14 operating day RATA po stponement for unforeseen equipment failure would apply separately for each unrelated, indepe ndent event. As such, if equipment operating under the 14 day RATA postponement provision should experience an unrelated failure prior to successfully completing a RATA, the 14 day clock w ould restart. On the other hand, if the same failure should recur in a similar situation, the 14 day clock would continue running and would not be reset. In the case of electrical electricity ge nerating facilities under contractual obligation with CalISO to have equipmen t available or owned and operated by municipalities that did not operate

### 235 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 long enough to conduct a RATA during the quart er in which it is due, the semi-annual or annual assessment could be postponed to the next calendar quarter provide d the follow criteria are met:

x The RATA was scheduled for the first 45 days of the calendar quarter in which it is due, but the equipment’s operating schedule prev ents completion of the RATA; and

x A passing Cylinder Gas Audit is conducted during the calendar quarter in which the RATA is due. Paragraph 2, Subdivision B, Attachment C, of Appendix A to both Rule 2011 and Rule 2012 establishes both the timeline and the frequency f or Semi-Annual Asse ssments to be performed for equipment monitored by CEMS. The purpose of thes e stringent testing requirements is to ensure the accuracy of the CEMS in monitoring SOx and NOx emissions. These Semi-Annual Assessments obligate facility permit holders to co nduct RATAs within six months of the end of the calendar quarter in which the CEMS was last tested. Alternatively, such RATAs may be performed on an annual basis, provided that the relative accuracies of the SOx (NOx) pollutant concentration monitor, flow monitoring system , and the SOx (NOx) emission rate measurement systems are all 7.5% or less. Furthermore, for CEMS on any stack or duct through which no emissions have passed in two or more successive quarters, the semi-annual assessments may be delayed until no later than 14 operating days after emissions pass through the stack/duct. Some RECLAIM facilities that have had to disconnect their equipment due to failures and remove it offsite for repair have requested to have their RATA due dates extended. Other RECLAIM facilities, specifically electrical electricity generating facilities that either have contractual agreements with CalISO to have their equipment available but not necessarily ope rating or are owned and operated by municipalities, have requested to delay their RATA testing until they have sufficient operating hours to conduct a RATA. Staff proposes to revi se Attachment C. B.2. of Appendix A in both Rules 2011 and 2012 by adding subparagraphs (c) and (d), to allow RATA postponements due to these extenuating circumstances. For facilities that have major sources that are physically unable to operate to conduct a RATA, postponement of the RATA due date to within 14 unit operating days from the first re-firing of the major source is proposed to be allowed only if the following requirements are met:

x All fuel feed lines to the major source are either disconnected or opened and flanges are placed at both ends of the disconnected or opened lines, and

x The fuel meter(s) for the disconnected or opened fuel feed lines are maintained and operated and associated fuel records showin g no fuel flow are maintained on site. There were concerns from operators that for someunits, disconnecting the fuel feed lines was not feasible. Alternatively, an operator can open the fuel strainers to accomplish the same goal. That

### 236 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 is, with the strainers open it would be possible for enforcement staff to get visual confirmation that no fuel is flowing to the units. For any hour that fuel flow records are notavailable to verify no fuel flow, SOx (NOx) emissions would be require d to be calculated using the maximum valid hourly emissions from the last 30 days of operation. Additionally, prior to equipment restart the Facility Permit Holder would be required to:

x provide written notification to the District no later than 72 hours prior to starting up the major source;

x start the CEMS no later than 24 hours prior to the start-up of the major source; and

x conduct and pass a Cylinder Gas Analysis (CGA) prior to the start-up of the major source. CEMS emissions data after the re-start of operations would only be considered valid if the Facility Permit Holder passes the CGA test . Otherwise, for a non-passing CGA, the CEMS data would be considered invalid until the semi- annual or annual assessment is performed and passed. For such invalid CEMS emissions data, SOx (NOx) emis sions would be calculated using the maximum valid hourly emissions from the last 30 days of operation, commencing with the hour of startup and continuing through the hour prior to perfo rming and passing the semi-annual or annual assessment. For electrical electricity generating facilities either having contractual agreements with CalISO to have their major source availabl e but not necessarily operating, yet not having sufficient hours to conduct RATA testing or ow ned and operated by a municipality, amended rule language is being proposed to allow the postponementof the semi-annual or annual a ssessment to the next calendar quarter, provided that the facility demonstrates:

x the semi-annual or annual a ssessment was scheduled to be performed during the first 45 days of the calendar quarter in which the assessment is due but the assessment was not completed due to lack of adequate operational time, and

x a Cylinder Gas Audit (CGA) is conducted and passed within the calendar quarter when the assessment is due. Rules 2011 and 2012 - Typographical Edits The staff proposal would, if adopt ed, also make the following typographical clarifications and corrections:

### 237 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

x Under Rules 2011 and 2012 Appendix A, Attach ment C B.2.b the word “unit” would be added to offer clarity regarding the timeperiod for RATAs that are conducted on equipment for which no emissions have passed through any stack or duct in two or more successive quarters;

x The rule language “Proposed” and “Draft ” found in Rule 2011 Appendix A, Attachment C B.2.e., which inadvertently had been left in the previous amended rules, would now be deleted;

x Rule language found in subparagraph (e) of Rule 2012 Appendix A, Attachment C B.2, referencing “Chapter 2, Subdivision B, Para graph 10, Chapter 2, Subdivision B, Paragraph 11, and Chapter 2, Subdivision B, Paragraph 12” would be replaced with “Chapter 2, Subdivision B, Paragraphs 10, 11, 12, and 18”, to clarify relative accuracy requirements for fuel flow measuring devices; and

x Rule language found in subparagraph (e) of Rule 2011 Appendix A, Attachment C B.2 referencing “Chapter 2, Subdivision B, Para graphs 10, 11, and 12...” would be replaced with “Chapter 2, Subdivision B, Paragraphs 10, 11, 12, and 13...” to clarify the relative accuracy requirements for analyzers. Proposed Amended Rules 2011, Appendix A, AttachmentE and 2012, Appendix A, Attachment F – Clarification of “Standard Gas Conditions”
Standard Gas Conditions is defined in Rule2011, Appendix A, Attachment E and Rule 2012, Appendix A, Attachment F as “a temperature of 68 oF and one atmosphere of pressure.” Rule 102 – Definition of Terms, on the other hand, defi nes standard conditions for SCAQMD purpose of SCAQMD purposes other than RECLAIM as “a gas te mperature of 60 oF and a gas pressure of [1 atmosphere].” Similarly, the natural gas indus try uses standard conditions of 60 oF and one atmosphere. Many gas meters, including those used by natural gas utilities for billing purposes, automatically correct their readings to 60 oF and one atmosphere. As such, many RECLAIM facility operators need to convert their meter readings from the 60 oF and one atmosphere standard to the 68 oF and one atmosphere standard. While this conversi on is quite simple (multiplication by a constant factor of 1.015), it sometimes causes confusi on for facility operators, particularly for those with facilities where some, but not all, of the gas meters are corrected to 60 oF and others are uncorrected. It also makes the correction slightly more complicated for facilities with uncorrected meters simply because standard tables are read ily available for converting from actual conditions to the 60 oF standard but not to the 68 oF st andard. The proposed amendments to Rule 2011, Appendix A, Attachment E and 2012 Appendix A, A ttachment F would resolve this situation by giving each facility the operator the option to either the 60 oF standard or the 68 oF standard provided one or the other is used consistentlythroughout the facility for RECLAIM purposes.

### 238 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix Y – RTC Holdings as of September 22, 2015

ID Name Current IYB RTC Holding (tons) Current IYB RTC Holding (tons per day) 136 PRESS FORGE CO 3.6 0.01 346 FRITO-LAY, INC. 15.2 0.04 550 LA CO., INTERNAL SERVICE DEPT 17.6 0.05 710 TEXACO EXPLORATION & PRODUCTION INC. 2.0 0.01 1073 BORAL ROOFING LLC 24.2 0.07 1744 KIRKHILL - TA COMPANY 1.2 0.00 2083 SUPERIOR INDUSTRIES INTERNATIONAL INC 0.1 0.00 2418 FRUIT GROWERS SUPPLY CO 1.9 0.01 2825 MCP FOODS INC 2.2 0.01 2912 HOLLIDAY ROCK CO INC 1.6 0.00 2946 PACIFIC FORGE INC 2.5 0.01 3029 MATCHMASTER DYEING & FINISHING INC 3.8 0.01 3417 AIR PROD & CHEM INC 15.1 0.04 3585 R. R. DONNELLEY & SONS CO, LA MFG DIV 4.2 0.01 3704 ALL AMERICAN ASPHALT, UNIT NO.01 14.5 0.04 3721 DART CONTAINER CORP OF CALIFORNIA 3.5 0.01 3968 TABC, I NC 28.0 0.08 4242 SAN DIEGO GAS & ELECTRIC 48.3 0.13 4477 SO CAL EDISON CO 68.7 0.19 5973 SO CAL GAS CO 30.3 0.08 5998 ALL AMERICAN ASPHALT 1.4 0.00 7411 DAVIS WIRE CORP 2.4 0.01 7416 PRAXAIR INC 8.0 0.02 7427 OWENS-BROCKWAY GLASS CONTAINER INC 50.0 0.14 8439 EXXON MOBIL CORP 3.8 0.01 8547 QUEMETCO INC 24.4 0.07 8582 SO CAL GAS CO/PLAYA DEL REY STORAGE FACI 27.2 0.07 9053 VEOLIA ENERGY LOS ANGELES, INC 7.2 0.02 9755 UNITED AIRLINES INC 0.8 0.00 10141 ANGELICA TEXTILE SERVICES 2.0 0.01 11034 VEOLIA ENERGY LOS ANGELES, INC 8.2 0.02 11119 THE GAS CO./ SEMPRA ENERGY 0.9 0.00 11142 KEYSOR-CENTURY CORP 1.7 0.00 11435 PQ CORPORATION 24.9 0.07 11716 FONTANA PAPER MILLS INC 4.7 0.01 11887 NASA JET PROPULSION LAB 21.4 0.06 12155 ARMSTRONG WORLD INDUSTRIES INC 1.2 0.00 12372 MISSION CLAY PRODUCTS 3.7 0.01 12428 NEW NGC, INC. 15.0 0.04 12912 LIBBEY GLASS INC 0.0 0.00 13179 CRESCENT CRANES INC 0.2 0.00 14049 MARUCHAN INC 1.5 0.00 14092 CPC INTERNATIONAL INC, BEST FOODS DIV 1.3 0.00 14495 VISTA METALS CORPORATION 15.4 0.04 14502 CITY OF VERNON, VERNON GAS & ELECTRIC 2.1 0.01 14736 THE BOEING COMPANY 1.4 0.00

### 239 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

ID Name Current IYB RTC Holding (tons) Current IYB RTC Holding (tons per day) 14871 SONOCO PRODUCTS CO 2.4 0.01 14926 SEMPRA ENERGY (THE GAS CO) 2.9 0.01 14944 CENTRAL WIRE, I NC. 3.5 0.01 15381 CHEVRON USA INC 1.5 0.00 15504 SCHLOSSER FORGE COMPANY 10.9 0.03 16338 KAISER ALUMINUM FABRICATED PRODUCTS, LLC 4.8 0.01 16352 SO CAL EDISON CO 7.0 0.02 16639 SHULTZ STEEL CO 18.6 0.05 16642 ANHEUSER-BUSCH LLC., (LA BREWERY) 21.5 0.06 16660 THE BOEING COMPANY 2.2 0.01 16978 CLOUGHERTY PACKING LLC/HORMEL FOODS CORP 4.5 0.01 17344 EXXONMOBIL OIL CORP 1.8 0.00 17623 LOS ANGELES ATHLETIC CLUB 0.8 0.00 17953 PACIFI C CLAY PRODUCTS INC 42.6 0.12 17956 WESTERN METAL DECORATING CO 0.7 0.00 18294 NORTHROP GRUMMAN SYSTEMS CORP 16.9 0.05 18455 ROYALTY CARPET MILLS INC 2.7 0.01 18931 TAMCO 73.7 0.20 19167 R J. NOBLE COMPANY 7.1 0.02 19390 SULLY-MILLER CONTRACTING CO. 3.0 0.01 19989 PARKER HANNIFIN AEROSPACE CORP 0.1 0.00 20203 RECYCLE TO CONSERVE I NC. 1.4 0.00 20543 REDCO I I 0.9 0.00 20604 RALPHS GROCERY CO 2.9 0.01 21598 ANGELICA TEXTILE SERVICES 1.8 0.00 21887 KIMBERLY-CLARK WORLDWIDE INC.-FULT. MILL 8.7 0.02 22603 EXXONMOBIL PRODUCTION COMPANY 3.7 0.01 22607 CALIFORNIA DAIRIES, INC 4.1 0.01 22911 CARLTON FORGE WORKS 3.8 0.01 23752 AEROCRAFT HEAT TREATING CO INC 3.6 0.01 25058 EXXONMOBIL OIL CORP 1.8 0.00 25638 BURBANK CITY, BURBANK WATER & POWER 36.8 0.10 35302 OWENS CORNING ROOFING AND ASPHALT, LLC 4.3 0.01 36909 LA CITY, DEPARTMENT OF AIRPORTS 4.5 0.01 37603 SGL TECHNIC INC, POLYCARBON DIVISION 2.2 0.01 38440 COOPER & BRAIN - BREA 0.0 0.00 38872 MARS PETCARE U.S., I NC. 4.1 0.01 40034 BENTLEY PRINCE STREET INC 4.2 0.01 40483 NELCO PROD. INC 1.4 0.00 42079 ROD'S FOOD PRODUCTS 0.4 0.00 42630 PRAXAIR INC 2.8 0.01 42775 WEST NEWPORT OIL CO 2.0 0.01 43201 SNOW SUMMIT INC 68.5 0.19 43436 TST, INC. 18.9 0.05 45746 PABCO BLDG PRODUCTS LLC,PABCO PAPER, DBA 12.7 0.03 46268 CALIFORNIA STEEL INDUSTRIES INC 160.5 0.44 47781 OLS ENERGY-CHINO 17.4 0.05 50098 D&D DISPOSAL INC,WEST COAST RENDERING CO 1.5 0.00

### 240 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

ID Name Current IYB RTC Holding (tons) Current IYB RTC Holding (tons per day) 14871 SONOCO PRODUCTS CO 2.4 0.01 14926 SEMPRA ENERGY (THE GAS CO) 2.9 0.01 14944 CENTRAL WIRE, I NC. 3.5 0.01 51620 WHEELABRATOR NORWALK ENERGY CO INC 31.0 0.09 52517 REXAM BEVERAGE CAN COMPANY 11.1 0.03 53729 TREND O FFSET PRINTING SERVICES, INC 2.2 0.01 54402 SIERRA ALUMINUM COMPANY 7.2 0.02 56940 CITY OF ANAHEIM/COMB TURBINE GEN STATION 4.8 0.01 58622 LOS ANGELES COLD STORAGE CO 0.2 0.00 59618 PACIFIC CONTINENTAL TEXTILES, INC. 1.9 0.01 60531 PACIFIC FABRIC FINISHING 1.1 0.00 61722 RICOH ELECTRONI CS INC 1.7 0.00 61962 LA CITY, HARBOR DEPT 3.2 0.01 62548 THE NEWARK GROUP, INC. 4.6 0.01 63180 DARLING INTERNATIONAL INC 7.5 0.02 68042 CORONA ENERGY PARTNERS, LTD 12.7 0.03 68118 TIDELANDS OIL PRODUCTION COMPANY ETAL 2.9 0.01 73022 US AIRWAYS INC 0.7 0.00 74424 ANGELICA TEXTILE SERVICES 1.3 0.00 83102 LIGHT METALS INC 7.0 0.02 84223 NEWELLRUBBERMAID INC 0.8 0.00 85943 SIERRA ALUMINUM COMPANY 4.3 0.01 89248 OLD COUNTRY MILLWORK INC 1.4 0.00 94872 METAL CONTAINER CORP 12.1 0.03 94930 CARGILL INC 0.9 0.00 95212 FABRICA 4.7 0.01 96587 TEXOLLINI INC 0.4 0.00 97081 THE TERMO COMPANY 0.9 0.00 99588 DOMTAR GYPSUM INC 7.5 0.02 101337 NATIONAL O FFSETS 0.3 0.00 101656 AI R PRODUCTS AND CHEMI CALS, I NC. 101977 SIGNAL HILL PETROLEUM INC 4.5 0.01 105277 SULLY MILLER CONTRACTING CO 2.6 0.01 105903 PRIME WHEEL 0.7 0.00 107653 CALMAT CO 1.3 0.00 107654 CALMAT CO 2.7 0.01 107655 CALMAT CO 9.5 0.03 107656 CALMAT CO 2.9 0.01 113160 HILTON COSTA MESA 1.8 0.00 114264 ALL AMERICAN ASPHALT 3.3 0.01 115172 RAYTHEON COMPANY 2.1 0.01 115241 THE BOEING COMPANY 4.8 0.01 115277 LAFAYETTE TEXTILE IND LLC 0.0 0.00 115314 LONG BEACH GENERATION, LLC 43.2 0.12 115315 NRG CALIFORNIA SOUTH LP, ETIWANDA GEN ST 132.1 0.36 115389 AES HUNTINGTON BEACH, LLC 89.9 0.25 115394 AES ALAMITOS, LLC 273.0 0.75 115449 PLAYA PHASE I COMMERCIAL LAND, LLC 0.0 0.00 115536 AES REDONDO BEACH, LLC 147.0 0.40 115563 NCI GROUP INC., DBA, METAL COATERS OF CA 1.0 0.00 115663 EL SEGUNDO POWER, LLC 247.8 0.68 117140 AOC, LLC 2.0 0.01

### 241 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

ID Name Current IYB RTC Holding (tons) Current IYB RTC Holding (tons per day) 14871 SONOCO PRODUCTS CO 2.4 0.01 14926 SEMPRA ENERGY (THE GAS CO) 2.9 0.01 14944 CENTRAL WIRE, I NC. 3.5 0.01 51620 WHEELABRATOR NORWALK ENERGY CO INC 31.0 0.09 52517 REXAM BEVERAGE CAN COMPANY 11.1 0.03 53729 TREND O FFSET PRINTING SERVICES, INC 2.2 0.01 54402 SIERRA ALUMINUM COMPANY 7.2 0.02 56940 CITY OF ANAHEIM/COMB TURBINE GEN STATION 4.8 0.01 58622 LOS ANGELES COLD STORAGE CO 0.2 0.00 59618 PACIFIC CONTINENTAL TEXTILES, INC. 1.9 0.01 60531 PACIFIC FABRIC FINISHING 1.1 0.00 61722 RICOH ELECTRONI CS INC 1.7 0.00 117227 SHCI SM BCH HOTEL LLC, LOEWS SM BCH HOTE 1.5 0.00 117290 B BRAUN MEDICAL, INC 7.8 0.02 118406 CARSON COGENERATION COMPANY 118618 UNI-PRESIDENT (U.S.A.) INC 1.1 0.00 119134 ITW CIP CALIFORNIA 0.0 0.00 119596 SNAK KING CORPORATION 4.2 0.01 123774 HERAEUS PRECIOUS METALS NO. AMERICA, LLC 4.7 0.01 124619 ARDAGH METAL PACKAGING USA INC. 0.7 0.00 124723 GREKA OIL & GAS, INC 0.5 0.00 124808 INEOS POLYPROPYLENE LLC 2.0 0.01 124838 EXIDE TECHNOLOGIES 125579 DIRECTV 0.0 0.00 126498 STEELSCAPE, INC 14.2 0.04 127299 WILDFLOWER ENERGY LP/INDIGO GEN., LLC 25.2 0.07 128243 BURBANK CITY,BURBANK WATER & POWER,SCPPA 49.0 0.13 129810 CITY OF RIVERSIDE PUBLIC UTILITIES DEPT 10.1 0.03 129816 INLAND EMPIRE ENERGY CENTER, LLC 130211 PAPER-PAK I NDUSTRIES 6.3 0.02 131850 SHAW DIVERSIFIED SERVICES INC 7.6 0.02 132068 BIMBO BAKERIES USA INC 3.2 0.01 133405 BODYCOTE THERMAL PROCESSING 2.3 0.01 137471 GRIFOLS BIOLOGICALS INC 6.0 0.02 137508 TONOGA INC, TACONIC DBA 1.5 0.00 138568 CALIFORNIA DROP FORGE, INC 0.9 0.00 139796 CITY OF RIVERSIDE PUBLIC UTILITIES DEPT 14.7 0.04 141555 CASTAIC CLAY PRODUCTS, LLC 14.0 0.04 142267 FS PRECISION TECH LLC 1.2 0.00 142536 DRS SENSORS & TARGETING SYSTEMS, INC 0.1 0.00 143738 DCOR LLC 1.1 0.00 143739 DCOR LLC 0.2 0.00 143740 DCOR LLC 8.8 0.02 143741 DCOR LLC 3.5 0.01 144455 LIFOAM INDUSTRIES, LLC 0.7 0.00 146536 WALNUT CREEK ENERGY, LLC 57.5 0.16 148340 THE BOEING CO. COMMERCIAL AVIATION SRVCS 6.8 0.02 148896 VINTAGE PRODUCTION CALIFORNIA LLC 1.2 0.00 148897 VINTAGE PRODUCTION CALIFORNIA LLC 0.8 0.00 148925 CHERRY AEROSPACE 1.8 0.00 149491 BOEING REALTY CORP

### 242 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

ID Name Current IYB RTC Holding (tons) Current IYB RTC Holding (tons per day) 151394 LINN OPERATING INC 0.1 0.00 151415 LINN WESTERN OPERATING, INC 0.0 0.00 151532 LINN OPERATING, INC 7.8 0.02 151594 OXY USA, INC 2.8 0.01 151798 TESORO REFINING AND MARKETING CO, LLC 49.6 0.14 151899 VINTAGE PRODUCTION CALIFORNIA LLC 1.9 0.01 152054 LINN WESTERN OPERATING INC 0.0 0.00 152501 PRECISION SPECIALTY METALS, INC. 1.8 0.00 152707 CPV SENTINEL LLC 120.5 0.33 153033 GEORGIA-PACIFIC CORRUGATED LLC 0.6 0.00 153199 THE KROGER CO/RALPHS GROCERY CO 1.8 0.01 153992 CANYON POWER PLANT 42.0 0.12 155221 SAVE THE QUEEN LLC (DBA QUEEN MARY) 1.1 0.00 155474 BICENT (CALIFORNIA) MALBURG LLC 26.9 0.07 155877 MILLERCOORS, LLC 21.9 0.06 156722 AMERICAN APPAREL KNIT AND DYE 3.7 0.01 156741 HARBOR COGENERATION CO, LLC 20.9 0.06 157359 HENKEL ELECTRONIC MATERIALS, LLC 0.9 0.00 157363 INTERNATIONAL PAPER CO 1.5 0.00 158300 CITY OF ONTARIO 2.8 0.01 160437 SOUTHERN CALIFORNIA EDISON 144.8 0.40 161300 SAPA EXTRUDER, INC 5.7 0.02 164204 CITY OF RIVERSIDE, PUBLIC UTILITIES DEPT 9.2 0.03 165192 TRIUMPH AEROSTRUCTURES, LLC 2.8 0.01 166073 BETA O FFSHORE 168088 PCCR USA 2.4 0.01 169514 TITAN TERMINAL AND TRANSPORT INC 0.0 0.00 169678 ITT CANNON, LLC 0.3 0.00 169754 SO CAL HOLDING, LLC 104.4 0.29 171107 PHILLIPS 66 CO/LA REFINERY WILMINGTON PL 584.4 1.60 171109 PHILLIPS 66 COMPANY/LOS ANGELES REFINERY 139.7 0.38 172005 NEW- INDY ONTARIO, LLC 65.2 0.18 172077 CITY OF COLTON 16.4 0.04 173904 LAPEYRE INDUSTRIAL SANDS, INC 4.3 0.01 174406 ARLON GRAPHICS LLC 1.3 0.00 174544 BREITBURN OPERATING LP 2.4 0.01 174591 TESORO REF & MKTG CO LLC,CALCINER 133.7 0.37 174655 TESORO REFINING & MARKETING CO, LLC 839.0 2.30 175124 AEROJET ROCKETDYNE OF DE, INC. 1.6 0.00 175154 FREEPORT-MCMORAN OIL & GAS 2.5 0.01 175191 FREEPORT-MCMORAN OIL & GAS 9.4 0.03 176708 ALTAGAS POMONA ENERGY INC. 15.5 0.04 178639 ECO SERVICES OPERATIONS LLC 26.0 0.07 179137 QG PRINTING II CORP 0.6 0.00 179957 CA LOS ANGELES TIMES SQUARE LLC 2.6 0.01 180367 LINN OPERATING INC 39.9 0.11 180410 REICHHOLD LLC 2 1.4 0.00 700050 KEN BARKER 1.5 0.00 700084 SHELL NORTH AMERICA (US), L.P. 2.5 0.01 700126 GENERAL ELECTRIC COMPANY 113.3 0.31 700144 OLDUVAI GORGE, LLC 27.8 0.08 700161 KOCH SUPPLY & TRADING, LP 85.9 0.24

### 243 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

ID Name Current IYB RTC Holding (tons) Current IYB RTC Holding (tons per day) 700170 ABATEMENT CAPITAL LLC 20.2 0.06 700177 GREY EPOCH LLC 2.0 0.01 800003 HONEYWELL INTERNATIONAL INC 2.7 0.01 800016 BAKER COMMODITIES INC 9.3 0.03 800026 ULTRAMAR INC 561.4 1.54 800030 CHEVRON PRODUCTS CO. 1,289.1 3.53 800037 DEMENNO/KERDOON 4.6 0.01 800038 THE BOEING COMPANY - C17 PROGRAM 13.7 0.04 800042 ECO PETR INC (EIS USE ONLY) 0.6 0.00 800066 HITCO CARBON COMPOSITES INC 8.7 0.02 800067 THE BOEING COMPANY 2.2 0.01 800074 LA CITY, DWP HAYNES GENERATING STATION 189.5 0.52 800075 LA CITY, DWP SCATTERGOOD GENERATING STN 179.1 0.49 800080 LUNDAY-THAGARD COMPANY 18.1 0.05 800088 3M COMPANY 14.2 0.04 800089 EXXONMOBIL OIL CORPORATION 900.9 2.47 800094 EXXONMOBIL OIL CORPORATION 2.0 0.01 800099 NORRIS IND (EIS USE) 0.3 0.00 800110 THE BOEING COMPANY 1.3 0.00 800113 ROHR, INC. 8.6 0.02 800127 SO CAL GAS CO 41.6 0.11 800128 SO CAL GAS CO 179.7 0.49 800129 SFPP, L.P. 6.3 0.02 800149 US BORAX INC 4.2 0.01 800150 US GOVT, AF DEPT, MARCH AIR RESERVE BASE 7.4 0.02 800153 US GOVT, NAVY DEPT LB SHIPYARD 25.7 0.07 800168 PASADENA CITY, DWP 29.5 0.08 800170 LA CITY, DWP HARBOR GENERATING STATION 20.1 0.06 800181 CALIFORNIA PORTLAND CEMENT CO 1.5 0.00 800182 RIVERSIDE CEMENT CO 1.1 0.00 800183 PARAMOUNT PETR CORP 68.6 0.19 800189 DISNEYLAND RESORT 53.0 0.15 800193 LA CITY, DWP VALLEY GENERATING STATION 40.6 0.11 800196 AMERICAN AIRLINES INC 2.9 0.01 800205 BANK OF AMERICA NT & SA, BREA CENTER 1.6 0.00 800210 CONEXANT SYSTEMS INC 1.6 0.00 800253 UNION CARBIDE CORP 0.1 0.00 800264 EDGINGTON OIL COMPANY 17.0 0.05 800310 TA INDUSTRIES INC 0.5 0.00 800325 TIDELANDS OIL PRODUCTION CO 8.7 0.02 800330 THUMS LONG BEACH 2.6 0.01 800335 LA CITY, DEPT OF AIRPORTS 16.8 0.05 800337 CHEVRON U.S.A., INC (NSR USE) 8.8 0.02 800338 SPECI ALTY PAPER MILLS I NC 2.4 0.01 800342 ARTESIA KNITS INC 1.6 0.00 800344 CALIFORNIA AIR NATIONAL GUARD, MARCH AFB 0.7 0.00

### 244 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

ID Name Current IYB RTC Holding (tons) Current IYB RTC Holding (tons per day) 800371 RAYTHEON SYSTEMS COMPANY - FULLERTON OPS 2.3 0.01 800372 EQUILON ENTER. LLC, SHELL OIL PROD. US 16.4 0.04 800373 LAKELAND DEVELOPMENT COMPANY 0.0 0.00 800393 VALERO WILMINGTON ASPHALT PLANT 5.3 0.01 800408 NORTHROP GRUMMAN SYSTEMS 6.8 0.02 800409 NORTHROP GRUMMAN SYSTEMS CORPORATION 12.8 0.03 800416 PLAINS WEST COAST TERMINALS LLC 0.4 0.00 800417 PLAINS WEST COAST TERMINALS LLC 2.5 0.01 800419 PLAINS WEST COAST TERMINALS LLC 0.3 0.00 800420 PLAINS WEST COAST TERMINALS LLC 1.8 0.00 800436 TESORO REFINING AND MARKETING CO, LLC 667.9 1.83 TOTAL (TONS PER DAY) 26.5

### 245 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 

## Appendix Z – Comment Letters Received and Responses to Comments
The Public Workshop for RECLAIM was held on July 22, 2015. Comment letters received on and after that date are responded to below. Over the three year rule development process, many other letters, emails, and verbal comments have been received. These comments helped the rule proposal evolve, and staff apprec iates all the stakeholder input.
More recent comment letters have been numbere d and individual comment s within each letter have been bracketed and numbere d. Following each comment letter is staff’s responses to the individual comments.

Comment Letter #1 WSPA’s letter dated August 21, 2015, Phillips66 letter dated August 21, 2015

In addition to the letters above, the following comment letters were received from July 22 to August 10, 2015. The comments from these letters and staff responses are summarized in this Appendix, followed by an attachment that includes these comment letters.

Comment Letter #2 Norton Engin eering letter dated August 10, 2015 Comment Letter #3 Norton Engineering letter dated September 4, 2015 Comment Letter #4 Industry Coa lition letter dated August 21, 2015 Comment Letter #5 Latham & Watkins letter dated August 20, 2015 Comment Letter #6 Yorke Engineerin g, LLC letter dated August 21, 2015 Comment Letter #7 Charles F. Timms, Jr. August 21, 2015 Comment Letter #8 SCEC letter dated August 26, 2015 Comment Letter #9 Eco Servi ces letter dated August 28, 2015 Comment Letter #10 Charles F. T imms, Jr. dated September 17, 2015 Comment Letter #11 Southern California Edison (no date) Comment Letter #12 Inland Empire Energy Center – GE Capital dated September 22, 2015 Comment Letter #13 Earth Justice dated July 8, 2014 Comment Letter #14 Arnie Smithemail dated August 11, 2015 Comment Letter #15 Karl Lany email dated August 20, 2015 Comment Letter #16 George Piantka email dated August 14, 2015 Comment Letter #17 Chuck Case y email dated September 24, 2015

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### 266 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Responses to Letter #1
Response 1-1 Previous WSPA Comment Letters Please see staff’s responses to previous WSPA and the Industry Coaliti on’s letter and comments attached to the Draft Socioeconomic Staff Report.
Response 1-2 Shave Methodology and Ar bitrary Removal of Unused RTCs Staff disagrees with the commente r’s assessment in several areas. Intent of Control Measure CMB-01 and RTC Reductions It is important to understand that the Basin is currently classified as a “severe” non-attainment area for PM2.5 and “extreme” non-attainment for ozone. Based on recent data, the Basin did not meet the PM2.5 ambient air quality standards by the original attainment dateof 2014 or the revised attainment date of 2015. T hus, staff is obligated to find all tec hnological feasible and cost-effective control technologies to help the Basin achieve maximum emission reductions and attain the PM2.5 and ozone ambient air quality standards as expe ditiously as possible. Control Measure CMB-01 is a control measure in the 2012 AQMP that called fo r a total NOx reduction of 3-5 tpd in 2 phases: 2-3 tpd in Phase I with implementation date in 201 4 (already overdue) and 1-2 tpd in Phase II with implementation date in 2020. 7, 8 Staff committed to submit 3 tpd, the lower end of the range, to satisfy the SIP commitment. The intent of the Control Measure CBM-01 was not to limit the reduction to 3-5 tpd: 9

“It should be noted that since there are s ubstantial NOx reductions needed by 2023, if additional reductions are feasible and cost effective, they will be evaluated during rulemaking.”
The control measure also states that the District is required to monitor advances in BARCT, and if BARCT advances, the District is required to periodically re-assess the overall facility caps, and reduce the RTC holdings to applicable equi valent command & control BARCT levels.

7 The implementation dates are shown in Tables 4-2 and 4-4 of the 2012 AQMP

8 The 2 tpd in the statement that WSPA cited “The control measure will seek further reductions of 2 tpd NOx allocations if trigge red” on page 4-9 of the 2012 AQMP refers to the additional 2 tpd in Phase 2.

9 Page IV-A-60, Appendix IVA of the 2012 AQMP

### 267 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Staff has identified and evaluated all feasible and cost-effective BARCT to achieve 14 tpd RTC reduction as proposed in the PDSR. As stated in Control Measure CMB-01, the Control Measure did not limit the reduction to 3-5 tpd. There is no language in control measure CMB-01 that explicitly considered and rejected rem oving more than 2 tpd of unused RTCs. Regarding the implementation schedule for the 14 tpd RTC reduction, in the 5 years from 2009- 2013, the unused RTCs in the NOx RECLAIM program ranged from 5 to 8 tpd, 10 thus staff is proposing a 4 tpd RTC reduction in 2016. Additiona l reduction from imple mentation of BARCT will take 2 - 4 years for procurement, engineering, planning, and construction, therefore staff is proposing that the remaining shave of 10 tpd take place over 5 years between 2018 and 2022. Methodology for BARCT Reductions & Removal of Unused RTCs On contrary with the commenter’s assessmen t, Control Measure CMB-01 from the 2012 AQMP does not prescribe how the shave should be calculatedand thus it is not in conflict with the shave methodology. The proposed shave in the RE CLAIM program is estimated based on remaining emissions. This proposed method is consistent with past practice in the 2005 and 2010 RECLAIM amendments. To calculate the shave, staff first estimated the remaining emissions at BARCT levels projected to the compliance year 2023 including economic gr owth and 10% compliance margin. The shave was calculated as the difference between the current RTC holdings and the remaining emissions projected to 2023. Staff also re duced the shave by 0.85 tpd to account for uncertainties and provide some additional compliance margin. The total shav e proposes removal of RTCs necessary to attain BARCT levels of emissions, including removing some unused surplus RTCs in the market. Shave = Current RTC Holdings – (2023 Remaining Emissions + Uncertainty) = RTCs attributable to difference between 2000/2005 & 2015 BARCT + Portion of Unused RTCs = 26.5 – (11.67 + 0.85) = 8.8 + 5.2 = 14 tpd WSPA has suggested staff remove only the RTCs di rectly attributable to technology advancement (8.77 tpd) but not the unused RTCs. The unusedRTCs however create a dampening effect on RTC prices that allows RECLAIM facilities to purchase RTCs in lieu of implementing BARCT. For example, in 2009-2013, there were about 5 – 8 tpd surplus RTCs in the market and the average RTC prices were in a range of $1,162 – $5,491 per t on compared to the aver age cost-effectiveness

10 Table 1.1 of the Preliminary Draft Staff Report

### 268 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 of control range $8,300 - $13,000 per ton. 11, 12 Thus, the facilities opted to purchase low cost abundant surplus RTCs to reconcile their emission s at the end of the compliance year in lieu of installing control to reduce “real” emissions. For example, the refineries did not install any SCRs in responses to the 2005 NOx RECLAIM amendment even though staff had estimated about 51 SCRs would be installed by 2011. Removing surp lus RTCs is therefore critically important to ensure the effectiveness of the RECLAIM program and meet state law requirements to require the use of BARCT for existing sources. WSPA has suggested staff estimate the shave based the projected actual emissions but not the current RTC holdings. 13 However, removing 8.77 tpd from current RTC holdings will not be enough to ensure that the RECLAIM universe emits at an emission level that represents the maximum degree of reductions achievable as re quired by H&SC 40406. Staff analysis has shown that the RECLAIM universe can achieve a level of 12.5 tpd remaining emissions. To reduce RTCs from the current 26.5 tpd to reach the target of 12.5 tpd requires a “shave” of 14 tpd. A smaller shave would be met by simply giving up unusedRTCs, not producing any significant actual emission reductions. Compliance Margin RECLAIM facilities typically hold extra RTCs in their account to ensure that they will have enough RTCs to reconcile their emissions at the end of the compliance year. 14 Plant operation and emissions may fluctuate. CEMS may be offline an d facilities must use missing data procedures to calculate emissions which may be higher than actual emissions. Also, facilitie s may underestimate their actual emissions and need to hold a stream of RTCs to accountfor adjustments after audit. In previous RECLAIM amendments, staff provided 10% compliance margin to help the facilities deal with these uncertainties. Staff did the same in this amendment allowing a 10% compliance margin but actual unused RTCs may be even higher . As illustrated below, this level of compliance margin will result in 23% unused RTCs above the remaining emissions. St aff believes this will adequately meet the market’s need for unused RTCs.

11 Discrete RTC prices shown in Figure 1.2 of the PDSR: $1,162 - $5,491 per ton for 2005-2012.

12 Cost effectiveness for individual source categories: $11,000 - $17,000 per ton for refinery boilers/heaters >110 mmbtu/hr and FCCUs, $9,000 - $10,000 per ton for industrial boilers, $4,000 - $11,000 per ton for metal melting/heat treating and miscellaneou s combustion (page 3 of the Board Letter for the 2005 NOx RECLAIM Amendment, Agenda No. 25, January 7, 2005). Overall program average cost effectiveness: $8,300 - $13,000 per ton (page 8 of the Board Letter for the 2005 NOx RECLAIM Amendment, Agenda No. 25, January 7, 2005).
13 Industrial Coalitions’ Approach : Shave = Projected 2011 Emissions @ 20 05 BARCT – Projected 2023 Emissions @2015 BARCT = 8.77 tpd. Staff’s Approach = RTC Holdings – 2023 Remaining Emissions – Adjustment = 14 tpd

14 Page 54 the Staff Report of the 2005 NOx RECLAIM Amendment.

### 269 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Remaining RTCs after shave = 26.5 tpd – 14 tpd = 12.5 tpd Remaining emissions = 2.71 tpd (refinery) + 7.47 tpd (non-refinery) = 10.18 tpd Surplus RTCs = 12.5 tpd – 10.18 tpd = 2.3 tpd % Unused RTCs = 2.3 tpd / 10.18 tpd = 23% above remaining emissions The compliance margin is not expected to meetthe RTC holding requirements imposed under Rule 2005. Instead, staff has created a Regional NSR Holding Account to help facilities in the power sector subject to Rule 2005 NSR requirements. This Account will be taken from the 14 tpd shave and not from the post-shave unused RTCs. Staff ha s discussed this issue with the U.S. EPA to seek their approval on the concept and receive f eedback on whether or no t this concept can be applied to all RECLAIM facilities. Staff believes the compliance margin is not needed to create market liquidity. It is envisioned that the facilities would install control equipment to reduce emissions to the BARCT levels as required by state law and would create surplus RTCs to trade and keep the market liquid.
Response 1-3 Shave Application and Implementation Schedule At the inception of the RECLAIM program in 1993, the compliance year 2000 allocations were estimated for each facility in RECLAIM based on the methodology described in Rule 2002(d), and the compliance year 2003 allocati ons were estimated based on the me thodology described in Rule 2002(e). There was no “across-the-board” uniform percentage shave.
In the 2005 NOx RECLAIM amendment, a unif orm percentage shave (22.5%) was applied “across-the-board” because the BARCT identified at that time was applicable to “across-theboard” facilities (e.g. low NOx burners for ovens, kilns, furnaces.)
The shave for the SOx RECLAIM in 2010 was not distributed “across-the-board” because 1) the BARCT identified was applicable to only 11 major facilities, 15 and 2) the non-uniform characteristics of the market made it inequitable to distribute the shave to all facilities. 16 To ensure that the 11 major facilities would install BARCT equivalent to command-and-control and to keep other facilities in the market, the 2011 SOx shave was applied only to investors and onethird of the facilities in the SOx RECLAIM universe.
It should be noted that the methods used to establish the 1993, 2005 or 2010 shaves did not establish founding principles and precedence on how the shave must be distributed. How the shave

15 The 11 major facilities included six refineries, a coke calciner, two sulfuric acid plants, a cement plant, and a glass plant.

16 The 11 major facilities hold 87% of RTCs and contributed more than 94% of emissions. The remaining 21 facilities hold 6% of RTCs and contributed 6% of emissions.

### 270 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

should be distributed in each rule amendment is affected by the BARCT identified, the distribution of RTCs in the market, and staff’s analysis on how best to implement BARCT. For the proposed rule amendment, staff iden tified the new BARCT applicable for 20 major facilities (9 refineries and 11 non-refineries) and recommended shaving 56 facilities that hold 90% of the NOx RTCs and contributed 86% of the emi ssions. Staff proposed not to shave the remaining 219 facilities that hold only 10% of the NOx RTCs to keep them in the market. Regarding the different shave percentages for the refinery sector and the non-refinery sector, staff estimated that by implementing BARCT the refi nery and non-refinery sector could reduce 6.00 tpd and 2.77 tpd, respectively. Therefore, staff proposed shaving the RTC holdings from the refinery sector at a higher rate than the non-re finery sector weighted by the emission reductions that could be achieved. Staff proposed to shave the refinery sector by 66% and the non-refinery sector by 47%. The non-uniform shave is to ensure that the facilities subject to BARCT would install BARCT. After a shave of 22.5% “across-th e-board” in 2005, the refineries opted to buy unused RTCs and not install any SCRs to reduce NOx emissions even though staff had estimated it was feasible and cost-effective for the refineries to install 51 SCRs by 2011. In this case, if the percent shave were set at th e same amount “across-the- board”, facilities that do not have available BARCT, or where BARCT technology does not achieve the uniform 53% reduction, would have to purchase more RTCs from the refineries that can achieve 66% reduction. This would result in a redistribution of wealth fro m the non-refinery sectors to refineries. While this occurs to some extent under the staff pr oposal, the effect would be greatly increased. For CEQA and socioeconomic analyses, staff consid ered five alternative approaches to allocate the RTC reductions. All five alternatives have “across-the-board” shave. The challenge of the RECLAIM program is to find the most appropriate shave distribution to pr otect the environment, attain the NAAQS, satisfy state and federal CAA requirements and AQMP commitments, and at the same time, allow for economic growth, provide e quity, and safeguards for the functioning of the RECLAIM program. With respect to the implementation time, because th e implementation date fo r 2 tpd reductions in Phase 1 was due in 2014 and there are 5-8 tpd surplu s RTCs in the market, staff believes that at a minimum 2 tpd reduction or up to 4 tpd reduction shoul d be removed from the market no later than 2016, not “back-loaded” to 2019 as the commenter s uggested. As explained in Response 1-2, the removal of unused RTCs is expected to raise th e RTC prices and stimulatethe implementation of control equipment. It is urgent to implement the control equipment and reduce actual emissions as expeditiously as possible to meet the NAAQS for PM2.5 and ozone.

### 271 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Staff has planned for a sufficient lead time of approximately 2-3 years for the procurement, planning and engineering of BARCT. Except for the retrofits of Refinery 1’s gas turbines scheduled in 2018, staff currently estimated th at other retrofits would occur in 2019-2022 consistent with the commenter’s recommendation. Staff has estimated that Refinery 1’s gas turbines would be retrofitted in 2018 because the units have turnaround scheduled annually. This estimated schedule is used in the socioeconomic an alysis with an assumption that the unused RTCs will be removed from the market early.
Response 1-4 Useful Life of Control Equipment In the cost analysis for the proposed NOx RECLAI M amendment, staff has used a 25-year useful life for SCRs, LoTOx/scrubbers, and UltraCat appli cations. The commenter suggested that staff should have used a 10-year life since rule amendmen t is likely to occur in a 10-year interval (e.g. previous NOx RECLAIM amendment in 2005) and thus a 25-year life assumption makes the rule costs appear lower that they actually are by diluting the significant capital costs of required projects over a much longer time table than is likely to occur. Staff used a 25-year life to be consistent with the following facts: 17
1) The actual profile of SCRs in the SCAQMD: 27% of the refinery combustion equipment in the Basin has SCRs installed more than 25 year s ago, and 63% of the refinery combustion equipment has SCRs installed more than 20 years ago. These units are still in operation and thus support the assumption of a 25-year useful life in the cost analysis. 2) Other air districts’ staff has used similar assumption for control equipment life in their cost analysis: a) Some SCRs for refinery heaters inthe Bay Area were inst alled in 1984 and thus the Bay Area air district staff uses a 20-year useful life in rule development. b) The SCRs in the Santa Barbara air districtwere installed in 1980-1990’s and are still in good operating conditions, and thus the Santa Barb ara air district staff supports a 25-year useful life of control device. c) Staff found several BACT analyses fo r the air districts in Fl orida that used 20- or 25-year useful life for SCRs. 3) The EPA OAQPS Costs Guidelines use a 20-year life for control equipment such as SCRs in their cost analysis. 4) Air pollution control manufacturers that staff contacted indicated that 20- or 25-year life is a reasonable assumption for control device suchas SCRs, scrubbers, or LoTOx applications.

17 Presented at the April 29, 2015 Working Group Meeting.

### 272 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The commenter is concerned that a future RECLAIM amendment may require removal of equipment installed to meet the 2015 shave, so that the actual useful life is less than 25 years. This hypothetical has not been borne out by past ex perience. Even though the RECLAIM amendment was revised in 2005 and staff had es timated that the refineries woul d have to install 51 SCRs for refinery boilers/heaters by 2011, only 4 of thes e boilers/heaters were retrofitted with SCRs in responses to the EPA consent degrees or order of ab atement. None of the SCRs were installed in responses to the 2005 BARCT assessment. Staff 2015 BARCT analysis did not identify any control equipment that would need to be re moved in order to comply with the 2015 BARCT. Furthermore, BARCT requirements were not revise d in 2005 for refinery gas turbines, refinery SRU/TGTUs, refinery boilers/heaters >40 – 110 mmb tu/hr, glass melting furnaces, cement kilns and ICEs, thus the time interval between the BARCT assessments for these units is actually 22 years counting from the inception of the RECLAIM program in 1993. Adding several years allowed for planning, engineering, permitting, construction, and proc urement of control equipment, the total time interval between inst allations of control equi pment would be about 25 years. The commenter implied that CARB may use a 10-year life for control devices. SCRs or scrubbers for major stationary sources are more durable thancatalytic filters for mobile sources. CARB may use a 10-year life in their cost analysis for mobile source rules; however staff has consistently used a longer life when applicable in the cost analysis for major stationary sources: 1) a 25-year life was used in the cost analysis for electrostatic precip itators to control particulate emissions from FCCUs in Rule 1105.1; 2) a 20-year life was used for domes for refinery storage tanks in Rule 1178; 3) a 25-year life was used for SCRs in the 2005 NO x RECLAIM amendment; 4) a 25-year life was used for scrubbers in the 2010 SOx RECLAIM ame ndment; and 5) a 20- to 25-year life was used in Rule 1111. For other rules and regulations su ch as Rule 1146.1 and Ru le 1147 that addressed low NOx burners, staff may use less than 25-year li fe depending on the type of control equipment and stationary sources. Finally, the commente r’s concern can be addressed in any future RECLAIM amendment. In the event that the Board amends the rules in the near future to render obsolete any control equipment added, staff would add those stranded costs to the cost of that future amendment or consider a longer compliance schedule to maximize the useful life of the control equipment as much as possible.
Response 1-5 BARCT Analysis In its comment letter electronically delivered on August 21, 2015, the Western States Petroleum Association (WSPA) claimed that “[...] RECLAIM must achieve emission reductions equivalent to or greater than traditional command and contro l, or BARCT. Thus, a NOx shave equivalent to BARCT (which the District proposes at 8.77 tpd) would be the level for comparison with the Health and Safety Code provision stating that equi valent or greater reduc tions would be achieved

### 273 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 at `equivalent or less cost compared with curr ent command and control regul ations and future air quality measures that would otherwise have been adopted as part of th e District’s plan for attainment.’ Yet, SCAQMD does not seek merely its determined BARC T equivalency level of 8.77 tpd; it seeks 14 tpd of NOx reductions and has not demonstrated that such reductions will be achieved at equivalent or lower cost than BARCT. The additional 5.21 tpd reduction goes above and beyond BARCT. [...]”
1) Removing 8.77 tpd of NOx RTCs would not result in the BARCT -equivalent level of actual NOx emission reductions: BARCT requires actual emission reductions. The 2015 BARCT analysis demonstrated that there woul d be an actual NOx emission reduction of 8.77 tpd from the 2011-2012 activity levels at 2015 BARCTcompared to the same activity levels at 2005 BARCT. This represents 8.77 tpd reducti ons in actual emissions. If the overall NOx RTC holdings had closely matched the total am ount of actual NOx emissions from the NOx universe, the removal of 8.77 tpd of NOx RTCs would likely induce an equivalent amount of actual NOx emission reductions. Ho wever, over the past five years, actual NOx emissions from RECLAIM facilities fell below the overall NOx RTC holdings by 21-30%, resulting in approximately 5.45-8.41 tpd of unused NOx RTCs (unused for compliance purposes). Therefore, the removal of 8.77 tpd of NOx RTCs w ould first eliminate some, if not all, of these unused NOx RTCs from the market and only ther eafter result in actual emissions reductions. Therefore, total emission reducti ons would be less than the BA RCT-equivalent level of actual NOx emission reductions. The problem of excess unus ed RTCs is illustrated by the fact that the 2005 NOx shave did not achieve 2005 BARCT levels for the RECLAIM universe. The 7.7 tpd of NOx shave adopted in the 2005 RECLAI M amendments was phased in over the period of 2007-2011; however, only about 4 tpd of actual NOx emission reductions occurred between 2006 (the year before the 2005 shave began) and 2012 (the year after the 2005 shave was fully phased in). Almost two-thirds of the actual emission reductions resulted from facility shutdowns, not installation of controls or other changes at RECLAIM facilities. Therefore, as long as there are persistently unused RTCs ava ilable in the market, the RTC shave would need to be larger than the tons of emission reductions calculated fo r the BARCT analysis to induce an equivalent level of actual emission reductions. The proposed pha sed-in shave of 14 tpd is anticipated to be able to induce sufficient e mission reductions by 2023 so that the expected total NOx emissions from the RECLAIM univers e in 2023 would be consistent with the projected NOx emissions in 2023 at the 2015 BARCT levels. (Please see the Staff Report for the shave methodology.) In summary, staff disagrees with WSPA’s comme nt that the proposed phased-in shave of 14 tpd would go “above and beyond BARCT.”
2) Installation of pollution control equipment is just one of the comp liance options and the estimated control installation costs may no t be fully incurred to achieve the BARCTequivalent level of actual NOx emission reductions: Unlike the traditional command-andcontrol regulations that typically requires the installation of pollution control equipment on all

### 274 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015emission sources, a RECLAIM facility has the flexibility of using RTCs to offset its facilitywide emissions and is expected to do so whenev er it is the least costly option. Since the 1970s, economic research has demonstrated, both theoretically and empirically, that the compliance flexibility offered by such cap-and-trade programs generates cost-savings (e.g., Tietenberg 1990; Chan et al. 2012). 18
The major source of the cost-savings under any cap-and-trade program is the differential in each market participant’s ability to cost effectiv ely reduce emissions. For a facility that can more cost-effectively reduce emissions, it benefits from the sale of surplus emission credits to offset pollution control installation costs; whereas for a facility that finds actual emission reductions too costly, it buys emission credits to account for the emission reductions that canbe more cost-effectively achieved elsewhere. Therefore, emission credit prices in a wellfunctioning market must lie in between the upp er and lower bounds of cost per ton of emission reductions among all market participants. If there is a large oversupply of emission credits and the market price ends up too low, there will be little incentive for facilities to implement any actual emission reductions. A RECLAIM facility is expected to retrofit an emission source only when it meets both of the following conditions: first, it does not hold sufficient RTCs to offset facility-wide emissions at the end of the compliance period; second, the cost of control inst allation per ton of emission reduction is lower than the expected average RTC price over the life of the control equipment. Even if a facility finds it more cost-effective to install pollution control equipment, it still would not incur the full cost of control installation if control installation results in surplus RTCs that the facility eventually sells to offset the c ontrol installation cost. In comparison, commandand-control regulations would require, under all circumstances, that this same facility install the control equipment and incur the full cost of control installation. As a result, total costs to install controls under RECLAIM will always be equal to or less than under command and control. Under command and control, each facility must install the required controls, whereas under RECLAIM, the highest cost option is wh ere each facility installs BARCT controls, because the total actual costs may be lower if a facility identifies any other more cost-effective alternative to remain in compliance.
3) California Health & Safety Code §39616 applie s, if at all, to the enti re RECLAIM program since adoption, and not to a single shave: The WSPA comment letter interpreted

18 Tietenberg, Thomas H. 1990. “Economic Instruments for Environmental Regulation.” Oxford Review of Economic Policy . 6 (1): 17-33. Chan, Gabriel, Robert Stavins, Robert Stowe, and Richard Sweeney. 2012. “The SO2 Allowance Trading System and the Clean Air Act Amendments of 1990: Reflections on Twenty Years of Policy Innovation.” Cambridge, Mass.: Harvard Environmental Economics Program.

### 275 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 that H&SC §39616 applies to the adoption of RECLAIM and also separately to each of the subsequent amendments. Staff disagrees with this interpre tation. H&SC §39616 (c) specifies that: “In adopting rules and regulations to implement a market-based incentive program, a district board shall, at the time that the ru les and regulations are adopted, make express findings.” One of those findings pursuant to H&SC §39616 (c)(1) is that emission reduction benefits and the costs of the pr ogram shall be compared withthose of “current command and control regulations and future air quality measures that would otherwise have been adopted as part of the district’s plan for attainment.” H&SC §39616 (c) does not refer to “amendments”. Nevertheless, assuming that the finding needed to continue to be ma de upon amendment of the rules, it makes sense to make that finding with respect to the entirety of the RECLAIM program since its adoption because the statute repeatedly refers to “the program” in specifying findings that need to be made. Thus, the structure of H&SC §39616 is directed to the program as a whole, which includes the entirety of the progra m since its adoption. With the exception of the 2000-2001 period when the California energy crisis took place, the histor ical discrete NOx RTC prices ($5,500 or lower per t on) have consistently been at the lower end of or below the cost-effectiveness range of pollution controls. As a result, many RECLAIM facilities have accrued substantial cost-savings over the years by being able to delay or forego the installation of pollution control equipment that would have been required at different points in time by command-and-control regulations. And even if the H&SC §39616 (c)(1) finding needs to be made for this proposed shave alone, the proposed shave is expected to only reduce the future stream of this cost-savings. Even so, a reduced cost-saving is still a cost-savings compared to command-and-control regulations. Thus, this amendment will clearly not cost more than the projected cost of command and control. Staff acknowledges that, for a portion of the smaller emitters that have no cost-effective controls identified so far, they may have been affected by past RTC price spikes and could potentially be impacted by any future price fluctuations, either due to their RTC holdings or their limited financial capacity to hedge against price volatilities. However, their potential losses would be at the same timeeconomic gains for the RTC se llers; therefore, the resulting net cost, if any, is expected to be zero or negligible to the entire RECLAIM program, particularly compared with the program’s cost savings. While individual facilities may experience different costs and savings, H&SC §39616 applies to the RECLAIM universe as a whole. It is misleading to separate the proposed NOx RTC shave into 8.77 tpd and 5.21 tpd and to argue that the 5.21 tpd shave of excess unused RTCs goes beyond BARCT, because BARCT is defined as the maximum degree of emissi ons reductions achievabl e (H&SC § 40406), and a shave of 14 tpd from current RTC levels of 26.51 tpd is necessary to attain the 12.51 tpd (26.51 tpd – 14 tpd = 12.51 tpd) of remaining NOx emissi ons in 2023, which staff analysis shows can be achieved with 2015 BARCT, after making allowances for growth, a compliance margin, and uncertainties that arose in the BARCT analysis. As a result, the 14 tpd shave does not go

### 276 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 beyond BARCT. For the same reason, it is a dist orted assertion that the estimated full control installation cost of $0.62-1.09 billion should be attributed to 8.77 tpd of NOx RTC shave only, with additional costs allegedly attributable to shaving the 5.21 tons of excess unused RTCs. This cost was estimated for actual NOx emission reductions of 8.77 tpd under command-andcontrol regulations, and it serves as the most conservative (i.e., maximum) estimate of the overall compliance cost for the proposed NOx shav e of 14 tpd that will be needed to achieve the BARCT-equivalent level of NOx emission reductions. As noted above, costs to RTC buyers are offset by gains to RTC sellers so that this factor does not increase costs to the RECLAIM universe. The claim that costs shoul d include the “value” of shaved RTCs is addressed below.
In the 2005 RECLAIM amendments, some stake holders commented that the shaved RTCs would result in real, significant financial cost to companies and should be recognized as a cost. However, staff disagreed at the time RECLAIM wa s first adopted and still disagrees today. Staff has never considered the “cost” of the shav ed RTC’s to be recognized as a “cost” for determining equivalency with command and control. At th e outset of RECLAIM, RTCs were allocated to RECLAIM facilities free of charge, yet they now have value to the facilities as a commodity that can be bought and sold. While RT Cs have value, they are not a property right. The proposed amendments to RECLAIM will reduce the number of RTCs. Since there was no cost associated with allocated RTCs for a faci lity, there should be no financial loss to the RECLAIM universe as the SCAQMD retires them. Any additional purchase of RTCs executed by a facility is made in lieu of emission control. The choice between the RTC purchase and emission control is solely a business decision that is made to generate an expected stream of cost-savings afforded only by the RECLAIM program and not available under command-andcontrol. Therefore, any RTC investment loss shoul d not be considered as a compliance cost to be compared to the compliance cost under comm and-and-control regulations. Moreover, this loss may be offset by any potential increase in RTC price due to a decreased RTC supply, which would subsequently raise the market va lue of a facility’s remaining RTC holdings. Finally, any loss of “value” of shaved RTCs cannot be compared to command and control, because in that case, there are no RTCs and thus no similar “value” was ever created.
4) Many unused RTCs are the result of shutdown selloffs, which have caused undue delay of BARCT-equivalent level of actual NOx emission reductions: According to staff analysisof the RECLAIM transaction records, many of the unused RTCs were sold, as Infinite-YearBlocks (IYBs), to operating RECLAIM facilities by some of the now-closed facilities prior to facility closure. These excess RTCs have been artificially depressing RTC prices and have induced RECLAIM facilities to delay the installation of cost-effective controls. A case in point is the 2005 NOx RECLAIM amendments. Despite 7.7 tpd of NOx RTC shave being implemented over the period of 2007-2011, only 4 tpd of actual NOx emission reductions had occurred by the end of the 2012 Compliance Year. Some of the 4 tpd of actual reductions came

### 277 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 from operational changes at refineries, which ch ose to run gas turbines instead of higheremitting boilers at various points in time. However, just less than two thirds of the 4 tpd actual reductions were due to facility shut-downs and not measures taken to reduce actual emissions by facilities in the program. In 2005, the sh ave amount was partially based on the BARCT analysis that included the installation of 51 SCR units at refineries. Howe ver, not one has been installed due to the RECLAIM program. (Four SCR units were installed only due to orders for abatement.) While that choice did not violate RECLAIM, it resulted in facilities not achieving the level of emissions they would have achievedhad they applied BARCT. As a result, there is a need to ensure that the currently proposedshave is sufficient to induce emission reductions equivalent to 2015 BARCT levels , accounting for growth to 2023. The original intent of RECLAIM, or any cap-and-trade program, is for all participating facilities to benefit from the differential in each operating facility’s ability to cost effectively reduce emissions. It is not to shift a closed facility’s prior pollution credits to any facility still in operation and cause undue delay of BARCT-e quivalent level of actual NOx emission reductions. (Under command-and-control, any pollution credits from a shut-down facility would at least be discounted by BACT.) As a re sult, staff proposes this level of BARCT-based shave to substantially reduce the amount of unused RTC credits in the market in order to better ensure the timely impleme ntation of BARCT as required under state law. Response 1-6 NEC Study Staff disagrees with the commenter’s suggestion that the BARCT cost analysis for the refinery sector needs to be revised to explicitly consider the findings presented by the Norton Engineering Consultants (NEC). First of all staff and NEC both obtained the same average cost effectiveness for refineries. Table 6.1.6 summarized the differ ences in staff’s and NEC’s findings in each category of sources:

Total difference in emission reductions: 6.00 tpd (staff) – 5.67 tpd (NEC) = 0.33 tpd Total difference in PWVs: $629 million (staff) - $562 million (NEC) = $67 million No difference in average cost-effectiveness fo r refineries = $11 K per ton (NEC and staff). Secondly, staff has reduced the proposed shave by 0.85 tpd to more than account for the difference in 0.35 tpd shown above and provideadditional compliance margin. The cost-effectiveness value of $11 K per ton estimated by both NEC and staff is lower than the estimated $16 K per ton for the Control Measure CMB-01 in the 2012 AQMP. 19
The difference between the two analyses occurs in the category of boilers/heaters. Staff’s estimates resulted in 0.33 tpd more emission reductions because 35 more heaters that were considered cost-effective compared to NEC’s estimates because NEC and staff used different cost

19 Page IV-A-58, Appendix IV-A, and Table 6-4 of 2012 AQMP.

### 278 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

data to estimate cost. Staff be lieves its proposal was reasonablesince its approach utilized information in the facility permits, information provided by the refineries through the Survey, and information provided by several prominent manufacturers of contro l devices for each specific category of sources. NEC used a verbal quote for one FCCU SCR to derive the costs for FCCUs, boilers/heaters and SRU/TG applications. The S CR catalysts for FCCU are not the same as the catalysts for boilers/heaters and SRU/TG applicati ons. Nevertheless, staff added 0.8 tpd to the remaining emissions (i.e. reduced the shave by 0.8 tpd) to allow for this difference. Further explanations are provided in Response 1-6 for FCCUs and Response 1-7 for boilers/heaters. Table Z.1-6 – Differences in Staff’s and NEC’s Findings

Category Proposed BARCT Emission Reductions Cost Effective Units PWVs Incremental Cost Effectiveness DCF (note 1) Conclusion

Boilers and Heaters with SCRs No difference 2 ppm Staff = 0.94 tpd NEC = 0.61tpd Diff. = 0.33 tpd Staff = 83 units NEC = 48 units Diff. = 35 units Staff = $242M NEC = $162M Staff = $28K/ton NEC = $29K/ton 0.85 tpd shave reductions

(note 2) FCCUs with SCRs No difference 2 ppmv No difference 0.43 tpd No difference 5 FCCUs (note 3) Staff = $152M NEC = $211M (note 3) Staff = $18K/ton NEC = $25K/ton No difference

SRU/TGTUs

with SCRs No difference 2 ppmv No difference 0.32 No difference 9 SRU/TGTUs Staff = $83M NEC = $96M Staff = $28K/ton NEC = $33K/ton No difference
Gas Turbines with SCRs No difference 2 ppmv No difference 4.14 tpd No difference 11 gas turbines Staff = $98M NEC = $53M Staff = $3K/ton NEC = $1K/ton No difference

Coke Calciner with LoTOx No difference 10 ppmv No difference 0.17 tpd No difference 1 coke calciner Staff =$54M NEC =$39.5M Staff = $35K/ton NEC = $25K/ton No difference

Total Staff = 6.00 tpd NEC = 5.67 tpd Diff. = 35 heaters Staff = $629M NEC = $562M Staff = $11K/ton NEC = $11K/ton 0.85 tpd shave reductions

(note 2) Note: 1) Ratio LCF/DCF = 1.6, e.g. $1K/ton DCF = $1.6K/ton LCF. 2) Staff provided 0.85 tpd reductions in shave to account for uncertainties in cost analysis assumptions for boilers/heaters and additional compliance margin. 3) Refinery 4 FCCU is scheduled to be shut-down in 2017-2018 which would result in lowering the costs estimated for this category.As shown in this table, except for boilers/heaters, the same equipment was identified as costeffective regardless of whether NEC costs or staff estimated costs were used, so there is no difference in calculated BARCT emis sion reductions. In the socioe conomic report, staff used the high end of the total costs. Response 1-7 NEC Study for Boilers/Heaters WSPA sassertsasserts that because only a few boilers and heaters are currently equipped with SCR are currently meeting 2 ppmv NOx , this level cannot be BARCT.

### 279 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

NOx Feasible Level First, it is important to note th at staff is obligated to find technology that can reduce maximum amount of pollution to help the basin achieve the ozone and PM2.5 standards and meet the requirement sated in H&SC §40406:

“... an emission limitation that is based on the maximum degree of reduction achievable, taking into account environmental, energy, & economic impacts by each class or category of source .” The two criteria required to be considered for BARCTare 1) technologically feasible and 2) costeffective. The feasible and cost-effective contro l technology must be considered BARCT even if they are not yet operational in the District. In th is case, WSPA admits that some units are currently achieving 2 ppmv which is strong evidence that this level is achievable. Staff is not required to focus only on achieved-in-practice and fully co mmercialized control tech nology (i.e. technology that is either being offered commercially by vendors or is in commerc ial demonstration or licensing) 20 . Staff can use a control technology that ha s been previously installed and operated successfully at a similar type of source, or has poten tial for application to th e source (i.e. has been successfully applied to similar sources with similar gas stream characteristics). For boilers/heaters category, staff included the analysis for SCRs as well as Great Southern Flameless and ClearSign as shown in Appendix B of the PDRS. Contrary to the commenter’s understanding, th e H&SC does not specify any threshold on the number of units that must be prove n achieved-in-practice for a control technology to be considered feasible. 21 As an example, in the 2010 SOx RECLAIM am endment, staff asse ssed and determined that a level of 10 ppmv SOx was feasible and cost-effective for a sulfuric acid plant using wet gas scrubber technology even though there was no sulfuric acid plant that had yet achieved this level. The sulfuric acid plant installe d a wet gas scrubber in 2011 after the rule was amended, sourcetested the unit, and demonstrated that the unit met a level much less than 10 ppmv. Regarding the count of boilers/heat ers, based on information receiv ed from the refinery Survey, 14 heaters using refinery fuel gas were reported to achieve 1.6 - 3.5 ppmv NOx with SCRs (Table B.3 of Appendix B). Four of the 14 heaters were reported to achieve 1.6 ppmv NOx. The heaters’ maximum ratings are 88, 125, 177, and 199 mmbtu/ hr. Based on information in the permit applications, three heaters were fi rst installed in 1970, the fourth h eater and the SCR were installed

20 American Coatings Assoc. v. SCAQMD, 54 CAL. 4TH 446 (2013)
21 American Coatings Assoc. v. SCAQMD, 54 CAL. 4TH 446 (2013)

### 280 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
in 1994. In 2004, all four heaters were modified to increase the overall heaters’ capacities, and thus all 4 heaters were subject to a permit limit of 5 ppmv NOx. It should be noted that the SCR has been in operation for 21 years and still achieves a level below 2 ppmv NOx. Thus, it is reasonable for staff to consider 2 ppmv as a feasible BARCT level.

It seems that the WSPA/ERM’s confidential surv ey in March 2015 reported different information than the information in the permits. It indicated that only 2 of the 4 heaters were retrofits and the remaining 2 heaters were new.

As stated above, besides SCRs, staff has also identified other control technologies that can potentially achieve 2 ppmv NOx level such as Great Southern Flameless, ClearSign, and LoTOx. A crude heater manufactured by Great Southern Flameless installed at the Coffeyville refinery in Kansas achieved 3-8 ppmv NOx without the use of SCR. Two boilers usin g natural gas equipped with LoTOx achieved 2-5 ppmv. ClearSign has recently signed a contract with Tesoro to retrofit a heater at Tesoro refinery and hopefully this project can be proven to achieve 2 ppmv NOx without the use of SCR. Great Southern Flameless, ClearSign, and several prominent SCR manufacturers provided staff the estimated costs of control equipment that can be designed to achieve 2 ppmv NOx. Response 1-8 FCCUs

WSPA contents that staff should not set a BA RCT level of 2 ppmv NOx for FCCUs because only one FCCU is currently achieving this level. Staf f is required to find technology that can potentially reduce maximum amount of pollution to meet th e requirement stated in the H&SC §40406 and help the basin achieve the NAAQS for ozone and PM2.5. Although staff recognizes that there are differences among different refineries, both staff analysis and NEC’s analysis identified 2 ppmv as achievable BARCT for FCCUs. Staff has evaluated two potential control t echnologies for FCCUs, SCRs as well as scrubber/LoTOx and estimated the co st-effectiveness values for both technologies to ensure that the control technologies were cost-effective. The SCR and LoTOx/scrubbers manufacturers confirmed that 2 ppmv is feas ible and provided cost information for the cost analysis. Each refinery may have unique circumstances (e .g. equipment type, age) and different upstream configuration, however the downstream control e quipment such as LoTOx/scrubber and SCR can be designed to achieve the 2 ppmv level as conf irmed by the manufacturers and agreed by NEC. There is precedent in identifying controls based on achievements by a single FCCU at the time the rule adoption. For example, in previous rule development in the SCAQMD, only one FCCU had

### 281 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

achieved the BARCT level of Rule 1105.1 at the time the rule was developed. 22 Likewise, only one FCCU in the Basin had achieved the BARCT level of 5 ppmv SOx at time the rule was amended in 2010. Regarding SCR costs, staff estimated a rang e of $152 million (no markups) to $163 million (with two layers of markups used by NEC). NEC estimated $211 million (with di fferent feed rates.) NEC’s estimates were about 40% higher than staff’s estimates. The SCRs were cost-effective at 2 ppmv using either NEC’s or st aff’s estimates. The cost eff ectiveness for FCCU SCRs has a range of $18K/ton - $25 K/ton.
Response 1-9 Costs and Cost Effectiveness Analysis
This comment asserts that staff’s BARCT anal ysis should be changed because NEC estimated higher costs for certain equipment. Cost Effectiveness fo r Refinery Sector

The costs and cost-effectiveness values for eac h individual class or category of sources are summarized in Table 6.1.6. The overall weighted aver age cost-effectiveness fo r the refinery sector based on NEC’s and staff’s es timates is $11 K per ton DCF ($18 K per ton LCF) with SCR technology, which is well below the thresholds th at the commenter cited for the BACT Guidelines and the 2012 AQMP.

Since RECLAIM achieves its reductions in th e aggregate rather than based on individual equipment, it is appropriate to l ook at cost-effectiveness in the aggregate using total program costs and total program reductions.

This comment also asserts that staff should have used the LCF methodology. Staff used a threshold level of $50,000 per ton DCF to exclude individua l equipment from the BARCT analysis to be consistent with the SOx RECLAIM amendment in2010. The cost-effectiveness values based on DCF and LCF methods are not di rectly comparable to each other: DCF discounts all future operation and maintenance costs to their present values whereas LCF amortizes the initial capital and installation costs over the equipment lifetime. This is why DCF values are always lower than LCF values for the exact same amount of estimate d compliance cost. Due to this methodological difference, staff disagrees with the commenter’s cl aim that the same cost effectiveness threshold should be used for both DCF and LCF methods. If the threshold for DCF was $50,000 per ton, the threshold for LCF should be about $80,000 per ton.

22 Rule 1105.1 – Reduction of PM10 and Ammonia Emissions From Fluid Catalytic Cracking Units, Adopted November 7, 2003.

### 282 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Cost Effectiveness Thresholds in BACT Guidelines

The commenter cited a threshold in the BACT Guidelines of $19,100 per ton NOx reduced. It should be noted that this threshold was estimated in the 2 nd quarter of 2003 and should be adjusted to $28,000 per ton as of 2015 dollars. The threshold considers the difference in costs and emissions between a proposed BACT and an uncontrolled ca se. The commenter ho wever should cite the threshold for “incremental” cost effectiveness whic h looks at the difference in costs and emissions between a proposed BACT and a less stringent contro l level. The threshold for “incremental” cost effectiveness is $57,200 per ton as of 2 nd quarter 2003 and should be adjusted to $80,000 per ton as of 2015 dollars. This is a more appropria te comparison when looking at two possible incrementally different levels of control. More important, these thresholds are for equipment located at non-major polluting facilities (also known as minor sources BACT, or MSBACT, in PartC of the BACT Guidelines). There are no thresholds for sources located at major polluting facilities such as the refineries, BACT/LAER is required without any cost consideration for sources located at major polluting facilities (Part A and B of the BACT Guidelines). Cost Effectiveness for Entire Proposed RECLAIM Project (Refinery and Non-Refinery)

This comment further asserts that RECLAIM fa cilities may be being treat ed disproportionately compared to facilities under command-and-control by having higher cost effectiveness. First of all, it is necessary to look at the RECLAIM program as a whole since H&S Code 39616 (c)(7) refers to “disproportionate impacts measured on an aggregate basis” on sources in RECALIM. As shown below, the cost effectiveness for the entire RECLAIM project, including refinery and nonrefinery, ranges from $7K - $12K per ton.
The PWVs for the entire NOx RECLAIM project as shown in Tables 4.3 and 4.4 (w/o cement kilns): Low end: $565 million (refinery) + $163 million (non-refinery) = $728 million High end: $923 million (refinery) + $176 million (non-refinery) = $1099 million
Total emission reductions: 6.00 (refinery) + 2.77 (non-refinery) = 8.8 tpd The overall range of cost-effectiveness for the entire RECLAIM project: Low end of range: 728,000,000/8.8/25/365 = $9,066 per ton High end of range: 1,099,000,000/8.8/25/365 = $13,686 per ton

### 283 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table Z.1-9 Cost Eff ectiveness Comparison Cost Effectiveness ($/ton) Proposed Amendment 9,066 – 13,686 Control Measure CMB-01 7,950 (P hase I) – 16,000 (Phase II) 23 Threshold in BACT Guidelines for “Minor Sources” 80,000 24 2012 AQMP 22,500 25

As shown in Table Z.1-9, the cost-effectivenes s for this proposed NOx RECLAIM amendment is less than the thresholds that the commenter c ited for the BACT Guidelines and the 2012 AQMP. They are also within the average cost effectiveness estimated for Control Measure CMB-01 in the 2012 AQMP.
Moreover, the NOx cost-effectiveness thre shold of $22,500 proposed in the 2012 AQMP was intended as a threshold above wh ich tiered levels of analysis would be conducted. It was not intended as a threshold above which a contro l measure would automatically be excluded. Therefore, this threshold should not be used to determine whether proposed rules or amendments would be cost effective. In conclusion, it is conservative in using a th reshold of $50,000 per ton fo r “incremental” cost effectiveness to eliminate cost-ineffective individual scenarios.
Response 1-10 Costs and Cost Effectiveness Analysis

This comment asserts that NEC conducted a comprehensive evaluati on of site-specific factors for each refinery, which staff did not appropriately c onsider. However, staff has maximized the use of site specific information provided by NEC on installation, design, engi neering costs, space needed, plant configuration, equipment type, equi pment age, length of time for SCR to operate and remain in service, and time needed for construction. As explained in response 1-6, in only one case di d NEC reach a different conclusion than staff regarding the appropriate BARCT (boilers/heaters). For that category, staff removed the emission reductions associated with equipment that was cost-effective under staff’s analysis but not under NEC’s analysis from the BARCT reductions (0.33 tpd. In fact, staff actually removed 0.8 tpd from the proposed shave.) The socioeconomic report give s appropriate consideration to the higher end of total BARCT costs.

23 Table 6-3 and 6-4 of the 2012 AQMP, and page IV-A-13 and page IV-A-58, Appendix IV-A of the 2012 AQMP 24 “Incremental” cost effectiveness on page 29 of the SCAQMD BACT Guidelines, dated July 2006, adjusted to 2005 dollars 25 Cited by the commenter, page 4-43 of the 2012 AQMP, February 2013

### 284 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

This commenter further asserts that staff did not properly cons ider installation, design, and engineering costs and that what is cost effective at one refinery may not be at another. Again, NEC confirmed, after visiting the sites, that sta ff’s proposed BARCT was appropriate for all cases except refinery boilers/heaters, described above. Staff looks forward to receiving the additional information WSPA states that it will submit. Response 1-11 Disproportionate Impacts

This comment asserts that RE CLAIM facilities may be disproportionately impacted because nonRECLAIM facilities represent the majority of stationary source NOx emissions yet the District does not appear to be seeking re ductions from them. The commenter also argues that reductions from non-RECLAIM sources must be “proportionate”. It is incorrect to assert that staff is not seeking reductions from non-RECLAIM sources. Staff is seeking emission reductions for all sources, RE CLAIM and non-RECLAIM, where feasible and cost-effective control technologies are available to help the basin achieve the ozone and PM2.5 ambient air quality standard as expeditiously as possible. Even though RECLAIM sources collectively account for 27 tpd NOx emissions while nonRECLAIM sources such as residential fuel combustion, waste disposal, and miscellaneous processes together account for 46 tpd, RECLAIM is th e fourth largest source of NOx emissions in the Basin and the top #1 emitting stationary sour ce. There is no requirement to reduce NOx emissions from all sources at the same time. Nor is there any requirement that all sources must reduce emissions “proportionately”, i.e. by the same percentage. Instead the law requires the District to seek BARCT-level reductions from all existing sources. BARCT is not a fixed percentage such as 40% or 50% reductions. Instead, it is defined as the maximum level of reductions achievable for each class or category of sources. For example, some equipment may be already relatively low-emitting so the maximum achievable reductions may be a smaller percentage, and some equipment may not have a cost-effective option available that will achieve the same percentage reduction as the RECLAIM sources. As long as each category implements the maximum reductions achievable for that category, there is no disproportionate impact. Staff has continually sought BA RCT NOx emission reductions from all sources, large and small. Recent examples include Rules 1110.2 (engines ), 1146, and 1146.1 (boilers, heaters, steam generators) and Rule 1147 (misce llaneous NOx sources). The District has regulated sources as small as residential water heaters (Rule 1121).

### 285 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Furthermore, the control tec hnologies that can reduce emissions from RECLAIM sources are commercially available and some are achieved-in -practice whereas the control technologies for many non-RECLAIM sources are being developed and not yet identified in the 2012 AQMP. In addition, the RECLAIM program offers many other benefits to the RECLAIM facilities which show that these sources are not suffering di sproportionate impacts on an aggregate basis.

 Source-specific standards. The non-RECLAIM facilities are subject to source-specific standards (e.g. concentration limit or mass emission limit) and every source (e.g. boiler or heater) at the non-RECLAIM facilities must be controlled to the same concentration limit or mass emission limit, and the source-specific command-and-control limit cannot be exceeded at all times whereas the RECLAIM facilities can operate their equipment with flexibility, they can purchase RTCs from other RECLAIM facilities to reconcile the emissions with the facility caps at the end of the compliance year in lieu of installing control;

 BACT Discount. The emissions from shutdown equipmen t at the non-RECLAIM facilities are required to be discounted to the BACT leve l before ERCs can be issued whereas the RECLAIM facilities can use or trade the RTCs associated with shutdown equipment without any BACT discount;

 NSR Offset Factor. The new or modifying non-RECLAIM facilities undergoing New Source Review (NSR) are required to offset any NOx orSOx emission increase by a factor of 1.2 to 1.0 ratio whereas the RECLAIM facilities are not subject to this offset. Instead, the RECLAIM facilities are required to hold sufficient RTCs based on their maximum potential to emit at a ratio of 1.0:1.0 at the beginning of each complia nce year, and they can sell back the unused RTC offset holdings at the end of each compliance year.

 Flexibility to Install Control. The RECLAIM facilities have the flexibility to install the least cost controls first, and have the flexibility to use the program averaging and cross-cycle trading to balance their compliance option.

 Trading. In addition, the RECLAIM facilities receive monetary benefits from trading their RTCs (equivalent to “Potential-to-Emit”) for the past 22-year life of the RECLAIM program to reduce the costs of compliance. Because of the many benefits available in the RECLAIM program, staff believes that the RECLAIM facilities are not being di sproportionately impacted by participating in the program.

### 286 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Response 1-12 Energy Ef ficiency Projects In responses to question #10 of the Survey Questionnaire, 26 the refineries sent to staff the CARB’s report released in June 2013. 27 Note that the actual emissions and the RTC holdings have different “currencies”. It is very likely that the 2011 emissions baseline already reflects the energy efficiency projects (i.e. 0.7 tpd co-benefit reductions were include d in the baseline.) However, The RTC holdings (“Potential to E mit”) were last adjusted in 2005, and at that time, the energy efficiency projects were not yet been completed, thus the RTC holdings (“Potential to Emit”) have not yet been reduced to reflect the energy efficiency projects. However, staff did not reduce the shave by 0.7 tpd to reflect the co-benefit reductions of the energy efficiency projects because this was used to offset the increase between the 2011 and 2012 emissions baseline for the refinery sector. The information on energy efficiency projects as part of the responses to the refinery Survey should be included in the PDSR. Response 1-13 Socioeconomic Impacts Staff is working on the socioeconomic report and the report will be made available soon.
Response 1-14 2012 Compliance Year Emissions Baseline Staff used the 2011 compliance year emissions as baseline because 2011 is the last year for implementation of the 2005 NOx RECLAIM amendment. Staff estimated the shave based on the remaining emissions projected to the 2023 co mpliance year. If the compliance year 2011 emissions were used, the growth factor from 2011- 2023 will be used to project the emissions to 2023. If the compliance year 2012 emissions, the growth factor from 2012-2023 will be used to project the remaining emissions. Both methods should result in the same 2023 remaining emissions for RECLAIM facilities assuming that the growth factors are projected reasonably accurate to reflect the change in emissions. For the refinery sector, staff used a [WW3][m4] growth factor of 1.0 provided by the refineries since the inception of the RECLAIM program in 1993. The 2012 compliance year emissions are 0.6 tpd higher than the 2011 compliance year emissions, thus the 2023 remaining emissions would be 0.6 tpd higher for refinery sector. However, there are 0.6 tpd co-benefits associated with the energy efficiency projects that were not being taking out of the RTCs holdings in the 2015 NOx RECLAIM amendmen t which would wash out the effect of the change in baseline year.

26 Appendix L of the PDSR 27 Appendix K of the PDSR

### 287 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Response 1-15 NEC’s Cost Analysis Refer to Responses 1-6, 1-7 and 1-10. On contrary to the commenter’s remarks, staff strongly believes the approach used is c onsistent with the requirements in H&S Codes in evaluating and conducting a technical feasibility and cost-effectiv eness analysis for the NOx RECLAIM project. Staff did not ignore NEC’s findings. On the contrary, staff has maximized the use of NEC’s site specific information on installation, engineerin g costs, space needed, plant configuration, equipment type, equipment age, length of time for SCR to operate and remain in service, and time needed for construction. Moreover, NEC reached the same conclusion as staff for BARCT for all refinery source categories except boilers/heaters. For that category, staff adjusted the BARCT goal by adding 0.8 tpd to the goal, which is more than enough to account for the emission reductions attributable to e quipment that was not cost-effective under the NEC analysis. Response 1-16 0.85 tpd for Uncertainties Refer to Response 1-7. Staff believes that providing 0.8 tpd RTCs is sufficient to account for the uncertainties and differences in the analysis re lated to boilers/heaters which amount to only 0.33 tpd difference in emission reductions between staff’s and NEC’s analyses
Response 1-17 Regional NSR Holding Accountfor Non-Electric Generating Facilities Staff has created a Regional NSR Holding Account to help facilities in the power sector subject to Rule 2005 NSR requirements. Sta ff has discussed this issue with the U.S. EPA to seek their approval on the concepts. Other facilities have more flexibility than Electric Generating Facilities to reduce their PTE and thus their required RTC hol dings if their actual emissions are lower than their PTE.
Response 1-18 Compliance Margin Refer to Response 1-2 for discussion on complian ce margin. The cement plant was shutting down but staff still included 0.29 tpd for the remaini ng emissions of cement kilns and 0.1 tpd for the remaining emissions of other shutdown facilities. Since the cement plant and other shutdown facilities are not coming back in business, this am ount of RTCs will serve as additional compliance margin to the entire NOx RECLAIM universe.
Response 1-19 Across-the-Board Shave Refer to Responses 1-3.

### 288 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Response 1-20 Emissions from 219 Facilities

Staff will revise the statement to state: “The remaining 219 facilities that hold 10% of the 26.5 tpd RTC are not proposed to be shaved because there is was either no new BARCT for the types of equipment and operation at these facilities (e.g. these facilities do not have FCCUs, coke calciner), or limited amount of emission reductions that could be achieved (less than0.1 tpd for ICEs and small boilers/heaters).
Response 1-21 Implem entation Schedule

Staff believes that the amount of unused RTCs in the market can support 4 tpd early reductions in 2016, and extending one more year from 2022 to 2023 may not be necessary.
Response 1-22 Longer P ublic Participation Staff has been conducted public meetings on th e proposed NOx RECLAIM for almost 3 years, and staff is planning for a public hearing in November 2015. The CEQA and socioeconomic analyses would be released for public comments according to the requirements in the H&SC §40440.5.
Response 1-23 Energy Ef ficiency Projects Refer to Response 1-12.
Response 1-24 CEQA Alternatives The size of the shave to represent 3-5 tpd of Control Measure CMB-01 of the 2012 AQMP would be about 11% - 19%, between the “No Project” Alte rnative (0% shave for Alternative 4) and the “Industry Proposal” Alternative (33% shave for Alternative 3).
Response 1-25 Cost Analysis Please refer to Responses 1-5, 1-9, and 1-10.
Response 1-26 Useful Life 25 Years Refer to Response 1-4.
Response 1-27 DCF versus LCF Cost Effectiveness

### 289 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Refer to Response 1-9.

Response 1-28 Reductions and Remaining Emissions Refer to Response 1-2 for the response addre ssing remaining emissions, Control Measure CMB01, shave methodology, and the necessity to seek fo r more than 5 tpd reductions as estimated in Control Measure CMB-01. Refer to Response 1- 11 for the response addressing disproportionate impacts. Refer to Responses 1-5 for the re sponse addressing H&S Code 39616 requirements.
Response 1-29 Compliance Margin Refer to Response 1-2. In addition, WSPA’s comment admits that the program has functioned on as little as 15% compliance margin, and has no t shown any need for the much longer amount of excess RTCs allowed by the industry’s proposal.
Response 1-30 Remaining Emi ssions for Refinery Sector Refer to Responses 1-6 and 1-7. NEC identified the same BARCT for all refinery categories except boilers/heaters. Staff provided 0.8 tpd reductions in shave to account for comments received from stakeholders regarding uncertainties in the BARCT analysis and thus provide additional compliance margin. Staff is required to show incremental cost effectiveness for the entire category of source and not for individual eq uipment. Thus, incremental emission reductions = 0.43 tpd (incremental emissions from 2005 BARCT) and incremental PWVs = $152 - $391 million for the FCCU category.
Response 1-31 Appendix A - FCCUs Refer to Response 1-6.
Response 1-32 Appendi x B – 2 ppmv Level for Boilers/Heaters Refer to Response 1-7. The count of boilers/hea ters presented at the September 19, 2013 Working Group Meeting (9 heaters having NOx emissions between 1.6 – 5 ppmv) was updated at a later date. The updated list in the PDSR showed 14 heaters with NOx emissions between 1.6 – 3.5 ppmv. Furthermore, the level of 2 ppmv not 3.5 pp mv should be considered as BARCT since it is “... an emission limitation that is based on the maxi mum degree of reduction achievable, taking into account environmental, energy & economic impacts by each class or category of source ”.
Response 1-33 Appendi x B – NEC’s Analysis for Boilers/Heaters

### 290 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Refer to Response 1-7. Several heat ers have already achieved this level presenting strong evidence that it is achievable. The difference in emission reductions between the two estimates was only 0.35 tpd and staff provided 0.85 tpd reductions in RT C shave to account for uncertainties in the assumptions of the cost analysis and additional compliance margin.
Response 1-34 Appendix B – Cost Analysis for Boilers/Heaters Staff does not understand the comment. The “pro grammatic” overall average cost effectiveness for boilers/heaters category is $27,529 ton NOx reduced as shown in Table B.11, page 77 and Table 4.3. Refer to Table 6.1-6 for comparison betw een NEC’s and staff’s estimates. Also, refer to Response 1-7.
Response 1-35 Appendi x D – Coke Calciner This comment supports staff recommended BARCT fo r this category. No response is needed.
Response 1-36 Appendix E – SRU/TGs Applications NEC’s cost analysis does not alter the BARCT c onclusion for SRU/TG app lications. There were no differences in emission reductions between the two estimates. NEC’s estimates of costs were 16% higher than staff’s estimates. SCRs were cost-effective with NEC’s and staff’s estimates of costs. See Table 6.1-6.
Response 1-37 Appe ndix K – Energy Efficiency Projects Refer to Response 1-12
Response 1-38 Shave Approach Refer to Response 1-3.

### 291 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #2 – NEC’s Letter Dated August 10, 2015

Comment 2-1 FCCU SCR Costs

NEC stated that they agreed that 2 ppmvd (3% O 2 ) NOx emissions is a justifiable emission level for SCR applications to FCCUs, Fired Heaters, Boile rs, Gas Turbines and TGU/ SRUs, with caveats..... NEC believed that it is possible to achieve these levels, but to guarantee long term reliable performance (refineries typically operate 24/7 f or periods of 4 to 6 years) it is prudent and quite possibly necessary to design future SCRs to in crease residence time, improve NH 3 distribution, improve overall flue gas flow distribution, add catalyst, etc. SCAQMD staff agrees with this concept but NEC and staff have strong disagreement as to how much change from current SCR designs will be required to achieve the sought after NOx reductions not onl y on day one but at the end of year one and year five and beyond. Response 2-1 Staff concurs that there may need to be a change from current SCR designs in order to achieve the 2 ppmv. As presented in the Preliminary Draft Staff Report (PDSR), the SCR profile for the refinery FCCU SCRs currently installed relies on 2-layers of catalyst. The NEC model is scaled to operate using 3-catalyst layers. This merely reflects a difference in engineering approach. NEC is arguing that the third bed is needed for reliability, however Refinery 1 has operated their FCCU SCR with two beds of catalysts and achieved less than 2 ppmv NOx since 2003 and several manufacturers provided costs based on SCR applications using a 2-layer catalyst bed that meet the proposed 2 ppmv BARCT emissions level, thus st aff believes that 2 layers of catalysts are sufficient. The NEC model is not based on or pr oposed for a specific SCR application, but instead provides a configuration that will achieve the same reductions. The resulting technical specifications between the two approaches are different, whereby the SCR box size, catalyst volume, and layer configuration, among other aspect s of installation, account for the difference in cost estimates. However, the potential additional cost to enhance SCR designs does not impact the total proposed reduction in RTC holdings.

Comment 2-2 Basis for Catalyst Addition and Velocity Reductions vs Vendor Budget Quotes
All FCCU SCR catalyst beds are in the range of 3 - 4’ deep, all are prone to plugging by catalyst and/or ABS and all have limitations on al lowable pressure drop, so superficia l velocity is a good basis for comparison between units. The district has three op erating FCCU SCRs. All uni ts have two catalyst beds and operate at superficial gas velocities in the range of 8 to 13 ft/sec. Two of the three units, operating at superficial velocities of 12 and 13 ft /sec do not achieve emissions of 2 vppm @ 3% O 2
. The other unit, highlighted in the draft report, achieves less than 2 vppm @ 3% O 2 operating at a superficial velocity of 7.7 ft/sec . The “good” unit is operating withinlet NOx levels which are 50% of

### 292 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
design or lower and at lower than design flue gas flows. There are several ways to bring the two “nonperforming” units into compliance with the revised standard, each with diff erent costs and different overall performance impacts. NEC was not commissi oned to do an evaluation of individual units and propose improvement options, but rather to make an a ssessment of what it woul d take, cost wise, to reliably achieve the 2 ppmv limit for grass root s SCR installations. Based on the experience of operating units in the district, and our direct expe rience with FCCU units for other clients (due to confidentiality agreements we cannot divulge client identities and specific locations) reliably achieving 2 vppm NOx emissions in an FCCU over a five year run will require the addition of catalyst and will be designed for superficial velocities of 10 ft/secor less. Considering that SCR catalyst vendors have not developed and guaranteed a specific SCR design for 2 ppmvd @ 3% O 2 NEC feels that it is prudent to assume that a third bed of catalyst (SCR or ASC) and cross section designed to achieve a maximum superficial velocity of 10 ft/sec is sufficient to characterize the most likely cost of a SCR unit capable of achieving 2 ppmvd in a typical refinery FCCU environment. The impact of the increased cross sectional area and the addition of a third bed of catalyst on the cost of an SCR installation has been overstated by district staff as a 284% increase in catalyst volume over manufacturer’s estimates. The increase over manufacturer’s budget estimates/propos als is actually 92%, one half of staff’s reported delta. Response 2-2 Staff understands the reasoning behind NEC’s methodology in determining the impact of the increased cross sectional area and the addition of a third bed of catalyst on the cost of an SCR installation. A review of Item 1 on page 121 of the PDSR indicated that the “total catalyst volume” was incorrectly stated and should have read “tot al SCR volume.” and was followed by an incorrect projected catalyst volume and space velocity. It is important to note that the NEC reports did not directly state the height of the catalyst layer within each SCR layer but referred to the SCR layer as 11 ft. Correspondence with NECs staff indicated that the catalyst layer height would be less than 55% of the SCR layer height and subsequentconversations with NEC projected the catalyst layer height within the range specified above. The uncertainty in the catalyst layer height may have contributed to the incorrect calculation of catalyst volume presented in the PDSR assessment in Appendix F. We concur that the increaseover manufacturer’s budget estimates/proposals is approximately 92 percent and the next version of the staff report will corrected.

Comment 2-3 Staff’s SCR Design Comparison Did Not Accurately Reflect NEC’s “Typical” FCCU SCR Design
Staff used an incorrect basis for comparing NEC’s typical FCCU SCR with district units in Table F.3. A revised comparison, using data fromRefineries 1, 5 and 6 is shown below.

### 293 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Table 1 (F. 3 Showing NEC Typical SCR) Performance Information of Existing SCRs Refinery 1 Refinery 5 Refinery 6 NEC Typical FCC Feed Rate, kBPD 95 71 84 55 SCR Inlet Flue Gas Flow, ACFS 6,585 5,525 9,685 3,848 SCR Manufacturer 1 3 2 -- No. Catalyst Layers 2 2 2 3 3 6,200 (1) (5) 4,600 Catalyst Volume, ft 2,975 6,200 Design Inlet NOx, ppmv (2) (3) 150 35 45 133 /40-80 Design Outlet NOx, ppmvd -- 17 6 2 NOx Measured, ppmvd <2 15-17 5.6 – 6.4 1.5 (Est.) Superficial Gas Velocity, fps 7.4 13.3 11.6 10.0 Space Velocity, 1/hr (6) (4) (5) 3,011 3,823 6,686 5,624 Removal Efficiency (3) 89% 83% 97% 95 - 97% Notes: 1. Staff incorrectly stated catalyst volume as 2,391 ft3 in Table F.3. 2,975 ft3 catalyst volume confirmed by NEC with Refinery 5 and via review of SCR data provided by Refinery 5 to SCAQMD. 2. Design value reported as 155 ppmv @ 0% O2. Value presented in table is corrected to 3% O2. 3. Measured outlet NOx value of <2 ppmv corresponds to operation of unit with inlet NOx in the range indicated. Removal efficiency based on range of actual operation. 4. Staff reports space velocity value of 2,974/hr in table F.3. 5. Confidential data provided by SCAQMD staff is insufficie nt to calculate the catalyst volume for this unit without making the following assumption on the depth of a catalyst module which we assume to be 45”. Staff used 1⁄2 of this value in Table F.3 corresponding to catalyst bed depth (catalyst element height) of 22.5”. Recommend staff confirm catalyst volume with Refinery 6. 6. Confidential data on unit design and performance, provided by SCAQMD staff, used to calculate inlet volumetric flow and space velocity. Values differ from staff’s entries in Table F.3.

Response 2-3 Staff has looked over the values presented in the abovementioned revised comparison. It is difficult to confirm several of the values presented inthis table and the notes. It is also important to note that the PDSR did not include the NE C model (proposed to achieve a 2ppmv emissionslimit) in F.3. Staff referred to the 3-catalyst layer NEC approach that was presented in the NonConfidential Final Report. The NEC data were encumbered in the Confidential Reports as a model for scaling FCCU SCR specifications and costs to the appropriate FCCU app lication. Furthermore, it should be noted that staff did not estimate the catalyst volumes or space velocities for Refinery 1, 6 or 5 as NEC stated in the footnotes of Ta ble 1 above. The numbers included in the PDSR were either reported by the refineries through the Survey or documented in the permit applications. Staff confirmed with Refinery 6 on the FCCU SCR catalyst volume and Refinery 6 reported the catalyst volume was not 6,200 c ubic feet as estimated by NEC in Table 1 above.

### 294 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 In addition, it is important to note that staff’s analysis in the PDSR relied on the manufacturers’ cost data provided to staff which did not project based on any specific superficial gas velocity or space velocity. The manufacturers provided costs based on a profile of the SCR currently used at Refinery 1 that rely on 2 layers of catalysts to meet 2 ppmv BARCT level. The bottom line is that NEC’s added cost based on a design including 3 la yers of catalysts would not affect the overall conclusion on the cost-effectivene ss of the FCCU SCRs and would not impact the total proposed reduction in RTC holdings.
Comment 2-4 NEC’s “Typic al” FCCU SCR Design
In their review, staff is suggesting that NEC’s typical SCR is overdesi gned and as a result overpriced. Staff’s comparisons suggest an overdesign factor of as much as 284%. We do not agree with this assessment. As can be seen in Table 1 (shown inComment 2-3) , NEC’s typical SCR should be able to achieve 97% NOx reduction by virtueof the addition of catalyst at higher gas velocities than the SCR operating at Refinery 1. The typical SCR de sign provides an approximate 21% margin in space velocity over the Refinery 1 SCR design primarily due to the addition of a third catalyst bed. The addition of a third bed has inherent performance advantages in that it provides for partial redistribution of unreacted NH 3 and NOx versus further cross sectional area additions. If it is determined that the incremental cost of specially fabricated catalyst modules (shorter depth) is low, some further optimization may be possible to reduce SCR cost. It is worth noting that the ~21% catalyst margin will have a 12% overall TIC and PWV cost impact.
Response 2-4 In reexamining our evaluation, staff agrees that yo ur typical SCR is not overpriced. Staff also understands the reasoning for your selection of a third catalyst bed, and as previously discussed, the PDSR erred in catalyst volume calculation. However, even with a 3 rd catalyst bed the change in overall cost-effectiveness would not impact th e total programmatic shave. Staff will continue to utilize our approach in deriving the costs based on the manufacturers’ information and Refinery 1’s profile of 2 layers of catalys ts to meet 2 ppmv BARCT level.
Comment 2-5 Mark-up factor 1.35 The following paragraphs provide background for NEC’s use of a 35% conditioning factor for vendor equipment quotes at early stages of proj ects. These concepts were discussed with SCAQMD staff during reviews of our report and insubsequent follow-up phone conversations and e-mails. Due to the extensive discussion ar ound this topic we are mystified by staff’s characterization of this “bid conditioning fact or” as, and here I paraphrase, ‘an undefined and therefore invalid cost increase’.

### 295 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Obtaining budgetary quotations from vendors for their equipment is part of the process of developing cost estimates for any project. At the early stages of projects, or when general information is sought, vendors are not provided comprehensive design basis information and therefore do not have a complete picture of the operating envelope for their proposed equipment. In these instances, some vendors will use costs from recent projects and “factor” them to the provided process conditions, othe r vendors may develop estimates based on equipment designed specifically to meet the provided process conditions. In either eventuality, the vendor is providing a quality estimate with reasonable accuracy (about+/- 10%) for the specified process conditions, without providing a performance gu arantee and without review of the specific codes and standards applicable to refinery installations. As project definition improves th e process basis becomes fixed, equipment sizes become more reliable, performance guarantees are finalize d, and vendor quote accuracy improves. Industry experience shows that at the early stages of a project, basis uncertainty alone, necessitates the addition of a 15 – 25% conditioning factor to a vendor’s budget quote, in addition to other bid conditioning factors, to account for the differen ce seen between early equipment bids and final, full definition, performance guar anteed, equipment bids based on a definitive project basis. Refineries are built to a more rigorous set of standards than typical air pollution control equipment which makes projects in the refining sector slightly more expensive than typical industrial projects. Standards which will have an imp act on either the SCR design, the structural support design, location of equipment, internal and external maintenance access, etc., are likely to increase Direct SCR M&L costs. At this stage of project defi nition a factor of 10% is added to a vendor’s equipment bid to account for the cost of meeting local plant standards. The 1.35 “mark-up” or bid conditioning factor usedin NEC’s cost work-up for all SCR projects (FCCU, Heaters/Boilers, etc.) is not an arbitrary fact or used to inflate costs, as implied in Appendix F, but is actually the low end of a time tested and proven means to determine the actual cost of a piece of equipment after full project definition is complete, including application of local industry standards to the design of the equipment, perform ance guarantees are offered and firm pricing for equipment components is provided by the vendor.
Response 2-5 Staff appreciates the in-depth background information of the bid conditioning factor, and regret the inclusion of language characterizing the use of the factor as “invalid”. The PDSR approach relies on the EPA model defined inAppendix A with a 50% continge ncy factor added to the cost estimate. However, staff recognizes NEC’s expertise in evaluating costs to place equipment in operation, but we will continue to utilize our approach in deriving the costs and will present your derived results for comparison. Staff derived th e SCR costs for Refinery 5, 6 and 7 based on

### 296 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Refinery 1 actual costs, thus the bid conditioning is not applicable here. For Refinery 4 and 9, the SCR costs were based on the costs provided by several prominent manufac turers and since SCR is a mature technology, staff feel s that a 50% contingency factor is sufficient. Even if the bid conditioning factor was used, staff’s estimates would be $163 million for 5 SCRs at Refinery 5, 6, 7, 4 and 9 (Appendix F) compared to $211 million as estimated by NEC. The bottom line is that NEC’s estimates of $211 million would not affect the overall c onclusion on the cost-effectiveness of the FCCU SCRs and would not impact the total the total programmatic shave.

Comment 2-6 75% increase in labor to the costs of the SCR
Another cost factor disc ussed with SCAQMD staff, and apparently dismissed as a simple adder to make costs appear high, is the cost of actually in stalling the equipment supplied by the SCR vendor in the plant. The vendor does not do construction and does not quote the cost of field assembly in their quote which only covers fabrication and supply of th e equipment, in this case the SCR catalyst, support frames, ammonia injection grid and the carbon steel box. The labor cost factor used in NEC’s development of project costs is applied to the SCR vendor’s factored estimate to account for the labor required to install the manufacturer’s equipment at the site, transportation, taxes, tie-ins, insulation, access, structural steel, etc. Installation labor for equipment can range from a low of about 30% of the equipment co st to as much as 200% of direct equipment cost depending on the complexity of the equipment, the mate rial it is made of and other equipment specific factors. In general, low cost equipment manufacture d of low cost materials have higher installation percentages than highly complex equipment made of high cost materials. As a reference point, “Applied Cost Engineering”, Clark F. D. and Lorenzoni A. B.; Marcel Decker Inc., 1978, uses a factor of 2.2 times direct material costs to estimate the direct M&L cost of a fired heater installation, a factor of 3.0 times direct material costs to estimate the direct M&L cost of a pump installation and a factor of 2.9 to estimate the direct M&L cost of a dist illation tower. Due to the simplicity of the SCR equipment and its use of low costmaterials we have used an in stallation labor cost factor of 0.75 (75%) to account for physical installation of the SCR, struc tural steel, fit-up of ducti ng, connection of piping, foundations, excavation, instrumentation, insulation, equipment storage, etc. This factor does not account for any costs associated with: demolition of existing equipment, modification of existing equipment, labor inefficiencies attributed to working in an operating plant, relocation and/or modification to underground utilities, piping, pipi ng supports, ammonia storage facilities, control system additions, instrumentation wiring, conduit, power wiring, area paving, area lighting, area utilities, safety facilities, soot blowers, etc.. The cost of these items is rolled up into the overall TIC factor applied to escalate SCR M&L costs to a total project cost. Response 2-6 As with the bid conditioning factor, staff conc urs that the NEC approach which adds a 75% labor cost factor is a valid alternate assessment of the projected project costs. As previously mentioned

### 297 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 we will present the information that you used in your assessment but we will continue to utilize our approach in deriving the costs. The PD SR approach relies on the EPA model with a 50% contingency factor added to the cost estimate. The EPA model did not have the 75% labor cost factor. Since the SCR technology is commercially available for more than two decades, staff did not feel that a 75% increase in labor is a necessit y. However, as shown in Table F.5, Appendix F, even if the 75% labor cost factor was include d, staff’s estimates would be $163 million for 5 SCRs at Refinery 5, 6, 7, 4 and 9 compared to $211 million estimated by NEC. The bottom line is that NEC’s estimates of $211 million do not affect the overall conclusion on the cost-effectiveness of the FCCUs and do not impact the total the total programmatic shave.

Comment 2-7 SCAQMD staff disputes NEC’s use of a TIC factor of 4.5 to convert direct M&L costs for the SCR into TIC for the SCR PROJECT. This factor is a reasonable estimate for project items not specifically identified in the dir ect M&L costs (indirect costs, engineering and owner’s costs, labor productivity, ancillary equipment and systems, re vamp items, duct work, area paving, lighting, utilities, safety systems, control system conn ections and programming, instrumentation, soot blowers, etc.) As a point of reference, the TIC fact or used by NEC, in this analysis, is 90% of the average TIC factor of 4.9 used to estimate SOx control costs in NEC’s SOx RECLAIM report.
Response 2-7

Staff appreciates NEC’s position on the TIC factor and agree with the reasonableness behind its selection. After the NEC Non-C onfidential Report was posted for re view, staff met with refinery personnel and their consultant s who provided examples of SCR equipment purchases and installations at out-of-state refi neries. Their data supported a 4.0-4.5 factor for PWV evaluation. Appendix A of the PDSR uses the 4.5 factor as an upper bound of cost estimation for the FCCU SCR PWV and cost analysis (i.e. $163 million for S CRs with 2 layers of catalysts). Staff reevaluated the EPA methodology in conjuncti on with a 50% contingency factor (i.e. $152 million for SCRs with 2 layers of catalysts). Regardless, use of both methodologies provides a range of expected costs.

Comment 2-8 SCAQMD staff is correct in pointing out that NEC used incorrect design capacities in developing the FCCU SCR costs shown in section 1.2 of NE C’s non-confidential report (14-045-4, November 26, 2014). NEC back calculated expected FCCU rate s from flue gas flow rate data provided by AQMD staff to obtain estimated FCCU sizes. The fo llowing table presents a revision to the report table based on corrected FCCU sizes as indicated by district staff. Also included in the table is an

### 298 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 update to the cost of a Grass Roots SCR for Refine ry 6 based on a comparison of flue gas rates to the SCR versus the typical (base case) SCR. Revised NEC estimates provided in Table 2 do not include any reduction to NEC’s original cost estimate model.
Response 2-8 Staff thanks NEC for back calculating the expected FCCU rates from the correct design capacities. However, staff cannot verify some of the assump tion in footnote 1 that NEC used for Refinery 6 and thus we continue to present the $211 million that NEC estimated. The bottom line is that NEC’s estimates of $211 million do not affect the overall conclusion on the cost-effectiveness of the FCCUs and do not impact the total the total programmatic shave.

Comment 2-9 Staff provided a review of NEC’s cost estimates based on a comparison to the cost provided for Refinery 1’s SCR to demonstrate that NEC’s es timating method is overly conservative. In this comparison staff claims that NEC’s cost tool over predicts the cost of this installation by $11M (27%). The difficulty in comparing a specific project to a generalized curve is that the project has a specific scope which in most cases is different than the assumed scope of the “typical” project. This is the case for the SCR installation at Refi nery 1 which, according to Refinery 1 personnel, did not include the cost for waste heat boiler modi fications. Subtracting this component from the TIC for a typical FCCU SCR installation and r ecalculating PWV yields a cost of $45.45M which is 10.8% higher than staff’s cost work-up on this project of $41M, not the 26% difference indicated in Appendix F. Staff had the WHB cost information NEC used in our estimates, we do not understand why they did not make the PWV comparison on the same basis.
Response 2-9 The PDSR estimation of Refinery 1’s PWV was base d on data provided by refinery staff. Staff took the data reported by Refinery 1 as the total project cost for the S CR system including all peripheral equipment.

Comment 2-10 Staff also provided a review of NEC’s cost es timates based on staff’s as sessment of differences between the data provided by an SCR vendor to st aff and NEC for an installation at Refinery 9. In staff’s evaluation of the data provided by the ve ndor they incorrectly calculate the total catalyst volume to be 3,100 ft 3 vs the actual vendor proposal which provided only 2,400 ft 3 . Staff also incorrectly calculates NEC’s estimated catalyst volume at 12,697 ft 3 vs an actual value of 4,600

### 299 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

ft 3 (1.92 x vendor proposal, see previous discussi on on catalyst volumes and specification of a third bed).
Response 2-10 With regard to your second comment first, staff agrees that the catalyst volume was incorrectly presented in the PDSR. The 12,697 ft3 actually re presents the total SCR volume. As presented in the PDSR, the manufacturer’s recommendati on for the Refinery 9 catalyst volume was 3,300 ft3. A review of the data provided by the S CR manufactures will be c onducted to conform to proposed specifications and correct an y misrepresentations in the PDSR.

Comment 2-11 NEC provides a few comments on SCAQMD staff’ s determination of PW Vs for FCCU SCRs. 1. In using the costs provided for Refinery 1’s SC R staff is assuming that all district SCRs can be installed without any impact on upstream equi pment and that installation of the SCR can be executed in an open, non congested area. Re finery 1’s SCR was in stalled prior to the installation of a large ESP, which occurred around 2006. If the SCR was to be installed today, or at any time after installation of the large ESP, costs would be higher due to productivity debits associated with working in a congested area and quite possibly even higher due to the need to move or modify some equipment to make the installation possible. In the most extreme case the SCR and ducting may have to be field erected from small fabricated assemblies due to access constraints. 2. Staff used a 0.7 power factor to scale the costs for Refinery 1’s SCR project to different sizes. Costs for FCCU regenerator flue gas systems s cale more accurately when a figure of around 0.6 is used. The effect of using a larger scale f actor is a greater reduction in project costs for all projects with the differences getting proportio nately greater the further one gets from the base case unit size. In essence using the 0.7 factor instead of 0.6, in this particular evaluation, will decrease costs for all units and will disproportionately decrease the cost of smaller units. 3. In using vendor budget quotes for SCRs, staff needs to add erection labor to the vendor quote. There is no indication that this is done in staff’s analysis. 4. Staff does not condition the vendor’s quotes to account for operational conditions, including unit upsets, and other project unknowns which will have direct bearing on SCR design details, performance and costs. An allowance must also bemade for the accuracy inherent in vendor’s budget quotations, which does not appear anywhere.

### 300 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 5. The PWVs provided for Refinery 7 and Refine ry 9 are $27M and $19M respectively. There is an apparent inconsistency in these numbers as the stated capacity for each of these units is 55 kBPD. Units of the same capacity should have PWVs close to one another not differing by 42%. Staff should check these numbers and en sure that the SCR project scope differences between these two units can explain the large difference in cost.

Response 2-11

Again, staff appreciates and respect NEC’s opinion withregards to our technical assessment of the FCCU costs. Staff notes areas of agreement and issues to be resolved.

1. Refinery 1 provided staff withcomprehensive cost data for its FCCU SCR. As such, we used this model to estimate PWV and associat ed costs for other FCCUs where applicable. Your comments are correct in asserting the uniqueness of Refinery 1’s situation, in particular the relative date of installation of an ESP to the FCCU. We realize that there are uncertainties in the cost estimate due to such considerations and have added a 50% contingency to our estimated costs. . 2. The PDSR based its scaling using a 0.7 factor established in practice and in the literature. The costs of $211 million estimated with the use of a 0.6 factor do not impact to the cost effectiveness calculation. 3. Staff concurs that the erection labor is a part of the installation costs included in the 4.5 factor 4. As previously stated, the PDSR cost estimates for the FCCUs included a 50% contingency factor to account for vendor cost estimation variability. 5. The PWVs for Refinery 7 and Refinery 9 were estimated using two different approaches. Refinery 7’s PWV was estimated based on Refinery 1 actual cost data while Refinery 9’s PWV was estimated based on the cost data submitted by the manufacturers. Originally, in 2013-2014 time frame, the manufacturers did not pr ovide cost data for Refinery 7, 5 or 6 since these FCCUs already have SCRs or wet gas scrubbers. In Table F.5 of the PDSR, staff provided 2 different approaches to estimate the costs for Refinery 7 and Refinery 9. Using the manufacturer’s cost data with 2 la yers of catalysts and no markups, the PWVs for Refinery 7 and 9 would be $20 million. Usin g the manufacturer’s cost data with 2 layers of catalysts and two levels of markups as recomme nded by NEC, the PWVs for Refinery 7 and 9 would be $31 million.

### 301 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #3 – NORTON Engineering – September 4, 2015

General Comments In its opening paragraph NEC is quoted “ We stated, quite clearly, in the final report and in subsequent discussions with staff, that we agree that 2 ppmvd (3% O 2 ) NOx emissions is a justifiable emission level for SCR applications to FCCUs, Fired Heat ers, Boilers, Gas Turbin es and TGU/SRUs, with caveats. While a few existing units can meet this guideline under current operating conditions, many more, similarly designed units ha ve not demonstrated similar low emissions capabilities. With the exception of Gas Turbine installations (which have an equivalent emission level of 6 ppmv @ 3% O 2 ) most low emission SCRs in service today, being built today and even those being designed today carry manufacturer’s guarantees to meet a NOx limit of 5 vppm @ 3% O 2 . In spite of the limited number of units (other than gas turbines) operating at or belo w 2 vppm NOx, we believe that it is possible to achieve these levels, but to guarantee long term reli able performance (refineries typically operate 24/7 for periods of 4 to 6 years) it is prudent and quite po ssibly necessary to design future SCRs to increase residence time, improve NH 3 distribution, improve overall flue gas flow distribution, add catalyst, etc. SCAQMD staff agrees with this concept but we havestrong disagreement as to how much change from current SCR designs will be required to achieve th e sought after NOx reductions not only on day one but at the end of year one and year five and beyond.” NEC also commented on the general approach to creati ng cost curves to determine an effective cost curve to represent the PWV vs the maximum boiler/heater firing rate. Their analysis highlighted the paucity of SCR data and questioned the linear approach taken by staff. They commented that their power law curve better captured the relationship (w ithin error bounds) when appl ied to specific Basin refinery SCR cases. They expressed that their co st curve better represented smaller heaters (<100mmbtu/hr heat release).
Response to General CommentsStaff recognized the issue and has directly quoted the NEC disclaimer from in the NonConfidential Report in Appendix B of the DSR to help define the primary difference in the control equipment specifications proposed by staff and NEC. With regard to the cost curve development a nd application, staff’s analysis expanded beyond a solely SCR application to includecontrol equipment including Great Southern Flameless Heaters, ClearSign Duplex technology for burners, as well as Electrodynamic Combustion Control technology. The staff analysis assessed the five sets of data to develop a set of representative PWVs to firing rates. Staff acknowledged in the DSR that cost curves developed by staff and NEC for higher firing rates converged and that the main difference was at fi ring rates less than 200 mmbtu. The differences between the cost curves generated by the varying control equipment design assumptions lead to the uncertainty reflec ted in the number of boilers and heaters deemed

### 302 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 cost effective. The uncertainty as defined by the difference in emissions reduced 0.33 tpd for the category has been accounted for in the 0.85 tpd adjustment to the shave.

Comment 3-1 Scope of NEC’s Review NEC indicated that staff agreed with NEC that any di lution of NEC’s effort to evaluate other alternative technologies than SCRs would not be desirable.
Response 3-1 Staff agrees that during an in-person conversation with Mr. Norton, the general understanding was for NEC to focus on SCRs as the primary contro l methodology. Regardless, staff sent to NEC information related to all control technologies discussed in Appendix A to Appendix E including technical studies, technical analyses, data that the refineries submitted as a result of the Survey, data that staff received from the manufacturers, facility drawings, facility permits, and manufacturers’ contacts for NEC to review. In an email, staff also introduced NEC to all of the manufacturers that staff contacted.

Comment 3-2 Using FCC SCR Costs Increased Heater & Boiler SCR Cost Estimates NEC explained the reasons that NEC elected to use F CCU SCR as the basis for its analysis for heater and boiler SCR. They cited uncertainty in vendor’s re sponse to their inquiries for additional data. They favorably compared a Basin refinery heater that achieved 1.6 ppmv to their FCCU SCR design and increase the costs to reflect installation of duct fan, new CEMS and ammonia storage tank.
Response 3-2 Staff agreed with NEC that the catalysts for FCCUs are not the same as the catalysts for boilers and heaters. Several prominent manufacturers indicat ed that a high dust application such as FCCU require a catalyst flow passage (or pitch) of about 7 mm. The refinery boiler and heater is a low dust application, and the catalyst pitch for this app lication is about 3 mm. The SCR for a refinery boiler and heater is generally compact and contains 1 layer of catalysts. The FCCU SCR contains 2 to 4 layers of catalysts, 2 or more filled with catalysts and 1 possible spare. The FCCU SCR has a large box area designed to fit additional equipment such as soot blower. Staff contends that NEC recommendation of 3 layers of catalysts for a FCCUSCR and 4 layers of catalysts for a boiler and heater SCR designed at 10 feet per second is different than a design provided by several prominent SCR manufacturers. The SCAQMD facility permit database contains information on the catalyst volumes of the SCRs currently in operation in the District. The table below shows the catalyst volumes for several SCRs at the refineries, the rating for the boilers/heaters in mmbtu/hr, and the NOx emissions in ppmv that the refineries reported through the Survey. On average, the catalyst volume for the boiler and

### 303 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 heater SCRs achieving 2 - 7 ppmv NOx is about 0.96 cubic feet of catalysts per mmbtu/hr based on the information in the facility permit database . The manufacturers indicated that the amount of catalysts needed to achieve 2 ppmv NOx is about 293 cubic feet for a 300 mmbtu/hr heater, and 92 cubic feet for 100 mmbtu/hr heater, or on average 0.96 cubic feet per mmbtu/hr. Staff estimated about 1.2 cubic feet per mmbtu/hr.

Table Z. 1 – Comparison of Information for Boiler and Heater SCR

Process Data NOx Emissions from Survey (ppmv) Heaters/Boilers’ Rating from Facility Permit Database (mmbtu/hr) Catalyst Volume from Facility Permit Database (cubic feet) SCR for 4 catalytic reformer heaters 1.64 589 537 SCR for a hydrotreating heater 2.26 78 92 SCR for 3 coker heaters 2.71 528 623 SCR for a crude distillation heater 2.7 83 62 SCR for a hydrogen plant heater 2.7 653 691 SCR for 3 hydrotreating heaters 2.67 63 92 SCR for a crude heater 3.31 85 96 SCR for a crude heater 5 300 120 SCR for a boiler 5.39 245 225 SCR for 3 crude distillation heaters 5.69 849 810 Average catalyst volume using information from facility permit database (cubic feet per mmbtu/hr) 0.96
Catalyst volume provided by manufacturers for 2 ppmv SCRs (cubic feet per mmbtu/hr)) 0.96 Catalyst volume estimated by Staff (cubic feet per mmbtu/hr) 1.2 Catalyst volume provided by NEC (cubic feet per mmbtu/hr) 17

Comment 3-3 NEC TIC Factor of 4.5 vs. Staff TIC Factor of 3.8 NEC explained the reasons that NEC elected to use a factor of 4.5 and the need to adjust vendor costs to include ancillary equipment such as ducting, fans, CEMS.
Response 3-3 Staff agreed with NEC and the refineries to us e a factor of 4.5 and adjusted vendor costs to include ancillary equipment such as ducting, fans, CEMS. Staff revised the estimates prior to the release of the PDSR. The revised estimates resulted in slig htly lower incremental emission reductions at a nominal increase in cost.

Comment 3-4 Basis for SCR Catalyst Increase and Velocity Reductions vs Vendor Budget Quotes

### 304 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
NEC indicated that staff analys is was based on only one SCR achi eving 1.6 ppmv. This SCR has 1 layer of catalysts, however the heaters were fi red at 65% capacity. NEC indicated that the vendor information provided by AQMD staff indicated th at doubling a vendor catalyst volumes would be needed to ensure reliable operation in excess of five years, thus the minimum number of layers of catalysts needed would be 1 layer x 2 / 0.65 = 3 la yers. NEC recommended 4 layers to ensure long term compliance while burning variable composition of refinery fuel gas. NEC also recommended 10 feet per second instead of 12 feet per second ve locity as recommended by the manufacturers.
Response 3-4 Several prominent manufacturers indicated that one la yer of catalysts is sufficient for a heater and boiler (or a gas turbine, or a SRU/TGTU incinerator) firing with refinery fuel gas. The SCR is typically designed at full rated capacity of the heater and bo iler to sustain an operation between 3-year to 5-year turnaround period. The manufacturers indicated that ev en though the refinery fuel gas may contain some components (e.g. sulfur) that may poison the SCR catalysts, they have not yet seen a significant impact on catalyst poisoning in refinery fuel gas applications. The manufacturers indicated that a welldesigned and maintained SCR system with good ammonia distribution syst em can meet 2 ppmv NOx.

Comment 3-5 Cost of New CEMS vs Upgrade and Ammonia Tank
NEC indicated that they did not have any dataon the status/condition of existing CEMS. NEC proposed the cost of a new CEMS at an approximate cost of $1 million. NEC indicated that they used used a common 11,000 gallons ammonia tank for all sizes of heaters and boilers in their proposals.
Response 3-5
The cost of $1 million for CEMS is not consis tent with the information submitted in CEMS applications. Staff understand the reason for a common 11,000 gallons ammonia tank and included the costs for ammonia tanks as recommended by NEC in the revised estimates prior to the release of the PDSR. This adjustment results in nominal change in costs.

Comment 3-6 High Catalyst Replacement Costs Skewed NEC PWVs High NEC indicated that NEC agreed with staff that replacement costs of the 4-layer SCR catalyst system would skew NEC PWV higher and NEC corrected their estimates.
Response 3-6

Staff concurs.

### 305 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015
Comment 3-7 NEC’s estimates are higher than staff’s “conservative” PWVs

The SCR listed in PDSR Table G.8 is shared betw een four heaters. The combined total rated capacity of the four heaters is 589 mmbtu/hr. NEC indicated that staff should have used $43.2 million as an estimate for a shared SCR of a 589 mmbtu/hr heater compared with $38.5 million to the total costs of the four individual SCRs that staff estimated. NEC estimated that 4 individual SCR units installed to meet the 589 mmbtu rating would require $99 M.
Response 3-7 Staff agrees that the common stack-shared SCR application is more appropriate and less costly that individual units being installed. NEC also noted that the difference in costs estimated by staff and their engineers was less than 12 percent.

### 306 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment Letter #4 - RECLAIM I ndustry Coalition, August 21, 2015 Comment 4-1 Shave amount and timing A shave of 4 tons per day in 2016 does not allow any time for facilities to develop and implement emission reduction measures. Th e Coalition believes that the shave amount for the period 2016- 2017 should be no more than 2 tons per day, and thatthere is no reason that all two tons have to be shaved in 2016.
Response 4-1 With respect to the implementation time, because the implementation date for 2 tpd reductions in Control Measure CMB-01 Phase 1 was past due in 2014 and there are 5-8 tpd surplus RTCs in the market, staff believes that at a minimum 2 tpd re duction or up to 4 tpd re duction should be removed from the market no later than 2016-2017. Staff disagr ees that this proposal does not allow adequate time for implementation because ther e are sufficient unused RTCs in the market to allow a 4 ton shave in 2016-2017 without requiring controls to be installed in those years. The removal of unused RTCs would raise the RTC prices and stimulate the implementation of control equipment. It is urgent to implement the control equipmen t and reduce actual emissions as expeditiously as possible to meet the NAAQS for PM2.5 and ozone.
Comment 4-2 Shave amount and timing There is no commitment in the AQMP to make a 4-ton per day shave in 2016. The AQMP contemplated a 2-3 ton per day reduction in Phase I and another 1-2 tons per day in Phase II. With respect to the total amount of the shave, the Coal ition continues to believe that shaving a total of 14 tons per day of RTCs from the RECLAIM market in order to achieve the 8.79 tons per day reductions the District seeks to obtain as a BARCTadjustment is neither necessary nor justified
Response 4-2 Please see Response 1-2.

Comment 4-3 Cost effectiveness The Coalition continues to believe that a 25 year useful life assumption (used consistently for all equipment in this proposed rulemaking) is not appropriate for all equipment.
Response 4-3 Please see Response 1-4.

### 307 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment 4-4 Cost effectiveness District staff minimizes control costs by using a cost-effectiveness calculation that is not used by the California Air Resources Board and most other major California air districts (i.e. LCF Method). Additionally, the use of a $50,000 per ton figure (i .e. based on DCF method) as the cost threshold is more than twice the $22,500 per ton threshold (i.e. based on LCF method ) applied to commandand-control regulated sources.
Response 4-4 Please see Response 1-9.

Comment 4-5 Cost effectiveness We also note that Norton Engineering (the third party independent contractor retained by the District to review and assess the District staff’s cost effectiveness determinations) has raised questions regarding the District staff’s cost effectiveness determinations and its dismissal of Norton Engineering’s analyses when those analyses showed higher costs than the District staff’s evaluation showed.
Response 4-5 Please see Responses 1-6.

Comment 4-6 Need for the “gap” Our analysis has shown that even if the District staff concluded that NO BARCT improvements had been made between 2005 and today, the staff’s methodology would result in 6 tons per day of NOx RTCs being removed from the program. RTCs being removed under the District’s methodology would include those needed for 1) NSR Holding Requirements, 2) Electric Grid Reliability and Implementation of AQMP Attainment Strategies (i.e., large scale electrification to replace current combustion processes), 3) Post- 2023 Growth, 4) Investor Holdings, 5) Shutdowns and 6) ERC Conversions. The Regional NSR Ho lding Account is to be used for both NSR Holdings and to cover actual emissions in certain cases which raises the question of whether it is large enough. The shave of 14 tpd is too larg e and runs the risk of repeating the program “meltdown” of 2000-2001 during th e power crisis when insufficient RTCs were available.
Response 4-6 Staff agrees with the commenter that using the staff’s methodology (Figure EX-1), if there were no new 2015 BARCT, the RTC shave would be:

### 308 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Allocations – (2011 emissions at 2005 BARCT x 1.1 for 10% compliance margin) = 26.5 – (1.1 x 18.3) = 6.4 tpd This shows that the 2005 shave was not large enou gh to remove the unused RTCs (or the “gap”) to the level that can stimulate the installation of actual control devices. Thus, in the past 10 years since 2005, there was only 4 SCRs installed at the refineries even though staff had estimated that it was feasible and cost effective for the refineries to install 51 SCRs by 2011. Staff methodology in estimating the remaining emissions in 2023 does include the impact of growth to 2023 and the possibility of returning op eration for shutdown faci lities and new electric generating facilities. Staff may need to revi sit the NOx RECLAIM post 2023 to incorporate advancement in control technology, but it is not appropriate to include post-2023 growth in the 2023 target as this will result in anartificially high target. Staff also creates a separate Regional NSR Holding Account to address the NSR hol ding requirements for new power producing facilities and is in the process of discussing with EPA to seek its approval. Moreover, the NSR Holding requirement and the use for power emergencies are not additive. Since the facility NSR Holding requirement is its maximum potential to emit, actual emissions will always be smaller and will be covered by the same RTCs used for the NSR Holding requirement. Investor holdings and ERC conversions are subject to shave consis tent with the previous 2005 and 2010 RECLAIM amendments. Staff has accounted for electric reliability by allowing “nontradable/nonusable” RTCs to become usable by power producers if a grid reliability em ergency is declared. Staff has accounted for increase electrification through the growth factor which assumes increased use of renewables. Note that ERCs of non-RECLAIM fac ilities do not hold their values to eternity, they are often recalled and reduced per Regulation XIII . Rule 2002 (f)(1) contains a safety valve to provide a stability for the RECLAIM market and ensure that when RTCs are not sufficiently available (i.e. the 12-month rolling average RT C price exceeds $15,00022,500 per ton), staff can convert the non-tradable/non-usable RTCs to tr adable/usable RTCs upon the concurrence of the Governing Board.
Comment 4-7 Energy efficiency projects The Coalition strongly opposes any effort to fu rther reduce RTC allocations due to “energy efficiency projects” that have or would reduce NOx emissions. Any reduction in NOx emissions not strictly required by BARCT should be encourag ed and the benefits of making those reductions retained by the facility operator making them.
Response 4-7

### 309 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Staff did not consider further reduce RTC allocations due to energy efficiency projects at this time. However, it should be noted that the energy effi ciency projects resulted in 0.7 tpd concurrent reductions of NOx completed in 2011, and the RTC allocations adjusted in 2005 have not yet been reduced to account for these reductions.

### 310 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment Letter #5 – Lath am & Watkins, August 20, 2015 Comment 5-1 March 20, 2015 freeze date for shave estimation The first time Harbor Cogeneration Company (HCC) was made aware of the freeze date of March 20, 2015 for shave estimation was just prior to the public workshop on July 22, 2015. However, staff proposal to establish a retroactive baseline date without prior advance notice constitutes an unprecedented ex post facto action that unfairly di sadvantages entities that ha ve made good faith trades after March 20. Two examples were prov ided and the commenter suggested the District propose the date of rule amendment as the freeze date for shave estimation. Response 5-1 Staff has revised the proposal a nd notified the stakeholders regard ing the proposed new freeze date of September 22, 2015. Staff cannot practically makethe freeze date for shave estimation the date of rule amendment because the rule language and calculation of shave must be completed for public review and comment prior to the Governing Board hearing for rule adoption. Staff disagrees that setting the freeze date prior to rule adoption is an “ex post facto” regulation. The prohibition on “ex post facto” laws or regulations applies to making conduct criminal that was not criminal when it occurred, or increasing the criminal penalty [in re Lomax, 66 Cal. App 4 th 639 (1998)]. In contrast, ordinary civil law may be made retroactive, but it must be expressly so stated in the language, or state statute, or clear form extrinsic evidence [Myers v Philip Morris Companies, Inc., 28 Cal 4 th 828 (2002)].

### 311 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #6 – Yorke Engineering, LLC., August 21, 2015
Comment 6-1 New Emission Factor s for Rule 219 Exempt Equipment We support the District’s August 19th proposal for new provisions in Rule 2012 Chapter 4 to allow equipment certified by either U.S. EPA, CARB, or SCAQMD to use an emission factor other than the default factor of 130 lb/mms cf to report NOx emissions. Response 6-1 An August 19 th presentation by staff acknowledged the issue and mentioned a possible path forward relying on source tests rather than the default factor. Based on feedback form stakeholders, the concept did not seem to achieve the goals of the request, and thus, staff is not proposing an alternative to the default factors at this time. Comment 6-2 Source Test for Rule 219 Equipment The District’s August 19th proposal for certified Rule 219 exempt e quipment indicates source tests may be required to verify lower emissions. We re quest that no source testshall be required for certified equipment. Response 6-2 Source testing is the preferred me thod of verifying the certified emissions for these units. The RECLAIM program offers the flexibility of a market program, but also has stricter standards for emission reporting than many command and c ontrol regulations. Based on feedback from stakeholders, the concept did not seem to achieve the goals of th e request, and thus, staff is not proposing an alternative to the default factors at this time. Comment 6-3 RTU Reporting The current requirements are sp ecified in 2012 Appendix A, Chap ter 7 – Remote Terminal Unit (RTU) Electronic Reporting. This section of the rule requires facilities to use dial-up modem technology to transmit a text string that must be very specifically formatte d. We have wasted hours of time working with this antiquated systemwhich is still requiredby the regulation. We urgently request that the Distri ct update their electronic reportin g system to allow more modern and easy to use technology. Response 6-3 We agree that the electronic reporting system n eeds to be updated. This upgrade, however, would be very resource intensive for SCAQMD staff and the affected operators and is outside the scope

### 312 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 of this rule making. The RTU electronic reporting system will be upgraded and the corresponding rulemaking will occur at that time. Letter # 7 - Charles F. Timms, Jr. August 21, 2015Comment 7-1 Electric Generating Facilities Need Quicker Access to Nontradable/Non -usable RTCs

Response 7-1 SCAQMD staff has taken your comments into cons ideration and has proposed a mechanism for accessing non-tradable/non-usable credits and also credits in the Regional NSR Holding Account with associated triggers. For the first year of the shave, the entire non-tradable/non-usable portion of a facility may be accessed if the rolling 12-month RTC price exceeds $15,00022,500/ton. Those credits would become usable and tradable. Th e non-tradable/non-usable credits would also be accessed if the Governor of California declares a State of Emergency, but would be usable/non-

### 313 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 tradable. Staff is not proposing a fee for acces s to the Regional NSR Holding Account due to comments received at Working Group and other m eetings from many other electric generating facilities that a fee should not be imposed for using these credits. The commenter also expresses that the non-trad able/non-usable RTCs notbe removed from the facility permits after the end of the shave as these credits will be greatly needed then. Staff has established the Regional NSR Holding Account su ch that the non-tradable credits for newer electrical electricity generation facilities that would normally go to the SIP after one year for each year of the shave would now go in the Regional account every year of the shave beginning in 2017. So when the shave is complete, the shaved portio n would be available to meet NSR purposes for these facilities and also provide relie f in the event of a power crisis. A regional hold account offers more flexibility than if each facility held the am ount reduced for their facility. For example, if there is a power emergency, not every facility will need to run. One or more facilities may be nonoperational, and it is conceivable that not all facilities will be called on to the same extent to operate during an emergency.

Comment 7-2

Response 7-2

### 314 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 As stated in the previous response, access to the Regional NSR Holding Account would be for credits that could cover NSR holding requirements for newer electrical electricity generating facilities, as well as covering annual emissions for all electrical el ectricity generating facilities in the event of a power crisis.

Comment 7-3 Two suggestions on the provisions related to the RATA testing:

Response 7-3 Staff believes that the due date of 14 operating days from re-firing of a major source is sufficient for performing a RATA. The operating days do nothave to be consecutive days so the total calendar days since the re-firing could be longer. The proposed amendment for requiring the disconn ection and flanging of fuel feed lines to demonstrate non-operation is necessary because this is the only reliable way to ensure that SCAQMD compliance staff can visibly confirm non- operation and no fuel flow. This prevents possible circumvention for other existing methods of demonstrati ng non-operation such as stack emission monitoring and recordkeeping.

### 315 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment 7-4

Response 7-4 The comment discusses the provisions regarding th e non-tradable, non-usable adjustment factors. The commenter states that 12 -month rolling average should be a weighted average. Staff calculates the rolling 12-month average by totaling the dollar sum of all the sales and dividing by the total sum of all the pounds (or tons). This price is reported monthly to the stationary source committee. The commenter also questions how the 12-month rolling average is determined for all trades in the current compliance ye ar when there are two cycles that overlap. Staff calculates the 12-month rolling average for all trades including cross-cycle transactions, but not including RTC transactions reported at no price or RTC swap tr ansactions. The commenter also pointed out a rule reference error in PAR 2002 (f)(1)(F). Staff has corrected the reference.

Comment 7-5

### 316 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Response 7-5 The comment discusses the provisions involving the Regional NSR Holding Account (previously called the Regional NSR Holding Account). The commenter asks how the account will be funded and whether additional funds will be needed to allow compliance with annual emissions. The Regional NSR Account will be f unded up to the amount that is shaved from those electric generating facilities that have multi-year NSR holding requirements each year of the shave. As stated in Response 7-1, for the first year of the shave the entire non-tradable/non-usable portion of a facility may be accessed if the rolling 12-month RTC price exceeds $15,00022,500/ton. Those credits would become usable and tradable. Th e non-tradable/non-usable credits would also be available for offsetting emissions if the Governor of California declares a State of Emergency related to power generation or grid stability, but would be usable/non-tradable. For NSR holding purposes, newer electrical electri city generation facilities can ac cess both their non-tradable/nonusable RTCs and the Regional NSR Holding Account RTCs. The commenter also asks why the State of Emergency declaration can only be made by the Governor and not by a local government official. Staff believes that a major power crisis would warrant this type of declaration and not just anelevation in power demand. Staff understands that there are other factors to consider, such as the increase in the electrification in the transportation sector that may cause the demand to rise. Combin ed with the lesser amount of RTCs available as

### 317 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 a result of the shave and higher resultant RTC prices, power-producing facilities may need some relief to gain access to more RTCs. Staff feels that the safety valves in the proposed amendment would address these concerns. Nonetheless, staf f proposes to add resolution language to monitor the power-producing sector for trends in power consumption and associated NOx emissions as electricity demand potentially increases. The commenter also states that the rule language needs to be clarified to detail that the Regional NSR Holding Account would accommodate NSR requi rements and annual emissions in the event of a power crisis. Staff has made these clarifications in the rule language and staff report. The commenter lastly states that it may not be appropriate for the Executive Officer to determine the amount and distribution of RTCs and thereb y make the determination of which electric generating facilities would generate electricity during a State of Emergency. Each individual electric generating facility subject to the shave would also have access to its non-tradable/nonusable account if the 12-month rolling average RTC price threshold trigger is reached, or if a State of Emergency is declared. The credits in the Regional NSR Holding Account would also be made available to all electric generating facilities under a State of Emer gency. If the State of Emergency is prolonged, the proposed amendments now provide for a report to the Governing Board after any power crisis trigger such that a plan for distribution of RTCs and possible program adjustments can be made before the supply of emergency RTCs is exhausted.

### 318 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter # 8 – SCEC Dated August 26, 2015

Comment 8-1
Responsiveness of Mitigating Actions. The Cities are concerned that rolling average RTC price may trail too far behind sudden RTC price increases and the requirement to obtain Governing Board authorization to convert the holdings to tradable a nd useable credits may not be suitably responsive to our needs as municipal utilities. In other words, the Ci ties’ need for certainty and swift access to RTCs may be jeopardized and we will be forced to participate in a market with escalating costs and limited RTC availability until the point that the $15,000 threshold is reached. By the time the SCAQMD responses are implemented, it will be too late to undo the damage to the utilities and local communities. Response 8-1

The comment states that if access to additional cr edits can be realized in a faster timeframe for unforeseen situations where emergency power ge neration may be necessary. The staff proposal has safety valves through which additional credits can be accessed, including the immediate access in the event of a power crisis. We understand that there may be some situations where the need to additional credits may arise more rapidly than, for example, a gradual upward trend in power generation. A facility would still have time to reconcile emissions at the end of a compliance quarter and compliance year, whic h include a reconciliation period.

Comment 8-2
Request for Flexibility in Accessing Non -tradeabletradable / Non-useable Holdings. The Cities are supportive of the proposals to expand access to credit s (at either no costs or $7.50 per pound which is equivalent to $15,000 per ton) and believe that they would be beneficial to the utilities and the RECLAIM program in general. By providing access to these credits in advance of a market upset, the District would provide municipal utilities the certainty needed to meet our mission at a reasonable cost and the limited access of utilities to their non-trad able credits may actually prevent market upsets that would trigger the widespread release of non-tradable/non-useable credits to all RECLAIM operators. Finally, if utilities are assessed a fee for their us e of the non-tradable/non-usable credits in advance of the 12-month price trigger being reached, the proceeds would be available to the District to facilitate voluntary NOx emission reductions
Response 8-2 The comment expresses support for the accessibility to non-tradable credits in the event of a market upset. SCAQMD staff has provided safety valves to provide access to the non-tradable/non-usable account and to the Regional NSR Holding Account in the event of the 12-month rolling average threshold price trigger being reached or in a State of Emergency. Other stakeholders do not believe there should be a cost to access such credits. Please see response 7-1.

### 319 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment 8-3
Sunset of Non-tradable/Non-usable Holdings. The Cities understand th at SCAQMD proposes to discontinue the non-tradable/non-useab le holdings in the year 2022. Given the uncertainty presented by increased integration of rene wable resources and regional electr ification, the Cities ask SCAQMD to provide for continued utilization of the non-tradab le / non-useable holdings, at least for municipal utilities.
Response 8-3 The comment requests that the non-tradable/non-usabl e holdings to be provided in perpetuity to municipal utilities. The staff proposal intends to su bmit the non-tradable portion of the shave into the SIP, and if they were held indefi nitely and could potentially be acce ssed, they would never be available for SIP emission reductions. Howeve r, for new electric generating facilities subject to multi-year NSR holding requirements, the shaved portions of holdings will go into the Regional NSR Holding Account. This account will hold the RTCs for NSR purposes in perpetuity and will provide relief to these facilities, while setting aside some RTCs for future uncertainty in the electricity market. Staff intends to include a resolution to closely monitor the impa cts of potentially increased electricity demand and renewable penetration on NOX em issions, and will propose RECLAIM program adjustments to the Governing Board if needed.

Comment 8-4
Regional NSR Holding Account, Com patibility of Dual Purposes. The Cities appreciate that SCAQMD is proposing alternatives that would ease the NS R holding requirement burden and also provide additional RTCs in the event of an emergency. However, it is not clear that both purposes can be simultaneously served, given the amount of RTCs that SCAQMD proposed to allocate to the account. The Cities ask that SCAQMD cl arify how the account can be avai lable for emergency use by all electrical electricity generating facilities, without jeopardizing the ability of new facilities to make the NSR holding demonstration.
Response 8-4: The commenter has concerns with how the Regional NSR Holding Account will be able to support the NSR requirements for facilities if the account is access ed by all electric generating facilities in a State of Emergency. The proposed rule language clarifies how the NSR Regional Holding Account would be implemented, and that it would be available to all electrical electricity generating facilities under a State of Emergency. There is no issue with us ing such RTCs for dual purposes. The NSR holding requirements cease after the compliance period ends, and if they are not used to offset actual emissions, the credits become available for other purposes. This is the situation as it exis ts today as RTCs can be sold after the compliance period ends.

### 320 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment 8-5

Additional entities or auth orities should be allowed to declare th e presence of an energy emergency at both a regional and local level. Many emergencies requiring local power generation may exist within the boundaries of a city and state or regional authorities may not be able to investigate and make the necessary declaration quickly. Local authorities, such as a City Manager or Mayor, should also be allowed to make a declaration that would allow for the release of RTCs from the Regional NSR Holding Account.
Response 8-5 The commenter asks why the State of Emergency declaration can only be made by the Governor and not by a local government offi cial. Staff believes that a major power crisis would warrant this type of declaration and that local emergencie s can be handled within the framework of the RECLAIM program, such as purchasing credits in the market to reconcile these emissions. If there is a necessity for credits, such an exceedance of the 12-month rolling average RTC price threshold trigger, then the non-tradable credits c ould be made available. See Response 7-5.

Comment 8-6

It is unclear how access to RTCs would be granted or how competin g applicants would be prioritized by SCAQMD to receive RTCs. SCAQMD must further define its role in the process of granting access to the Regional NSR Holding Account if the Cities are to be assured that credits are available not only for the NSR holding demonstration, but also f or easy access in case of an emergency.
Response 8-6 The comment requests for further definition as to how the Regional NSR A ccount credits will be prioritized for distribution. If the Governor declares a power emergency, the current year nontradable/non-usable RTCs held by electric generating facilities can be used to offset emissions after exhausting their own usable RTCs, unless they sold any part of their RTC holdings for the subject compliance year. If an eligible facility has exhausted their non-tradable/non-usable RTCs, it may apply for use of the accumulated RTCs in the Regional NSR account. The supply of emergency annual RTCs will be sufficient to handle a s hort term crisis. If th e crisis is prolonged such that the demand for emergency RTCs is greater than th e supply, there will be time to return to the Governing Board to make program adjustments. The staff proposal in cludes provisions to report to the Governing Board and proposes a plan for RTC distribution and other program adjustments when the State of Emergency access is triggered.

Comment 8-7

### 321 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

The Cities ask SCAQMD to clarify how the Regional NSR Holdin g Account would affect the way in which new power producing facilities would manage the remaining RTCs listed in their facility permits, with respect to the Rule 2005 (f) holding re quirement. Ideally, provisions to accommodate the holding requirement would also allow facility operators to sell the remaining unused RTCs listed in their permit in advance of compliance year closure . We also ask SCAQMD to give consideration to the same discretionary use of the Regional NSR Ho lding Account by municipal utilities that is proposed within this letter for the non-tradable/non-useable holdings.
Response 8-7 The comment requests for further clarity on how the Regional NSR Account will affect how the RTCs are reflected on the facility permits. Amounts of NSR holdings going into the Regional account year by year is listed in Rule 2002 for each facility. On the facility RECLAIM permits, Section B would still contain the usable/tradable and non-usable/non-tradable amounts, but the permit condition will refer to Rule 2002.The commenter also request the same use of the credits from the Regional NSR account to the nontradable/non-usable holdings. For newer electric generating facilities, the non-tradable/non-usable holdings and the holdings in the Regional account are essentially drawn from th e same pool of credits. For every portion of the shave designated as non-tradable/non-usable, the RTCs will go into the Regional account the following year, instead of being submitted into the SIP. Facilities would have access to the Regional account portion for offsettin g annual emissions if a State of Emergency is declared. The non-tradable credit portion for newer facilities would not be available for sale, however.

### 322 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment Letter # 9 – Eco Servi ces Letter Dated August 28, 2015
Comment 9-1 Eco Services does not support a program that leaves no reasonable means of complying. We support revisions to the RECLAIM program that rely on implementation of feasible and costeffective controls. Sources that can implement BA RCT can and should do so as a first step towards additional reductions. We strongly urge the SCAQMD to consider this approach which will result in a reduction of NOx emissions based on cost-effective controls which will not cripple the RECLAIM trading program and leave smaller emitters no real cost-effective option for compliance. If the SCAQMD pursues the across th e board shave, it will effectively be imposing cost-effective requirements on the BARCT sources but not considering cost-effectiveness at all for non-BARCT sources. Eco Services believes th at is inequitable and inappropriate. If the SCAQMD does pursue an across the board NOx shave, Eco Services recommends that the changes to RECLAIM include some type of measure to limit the costs of NOx credits in addition to the current $15,000 per ton annualized average cost , particularly for sma ll emitters. An equitable rule should provide the regulated community w ith a cost-effective means of complying. We request that the SCAQMD somehow provide a ceiling on the financial impact it will have onRECLAIM participants in terms of cost-effectiveness. BARCT sources will be subjected to costeffective controls. Similarly, th e financial impact to non-BARCT s ources should also be based on cost-effectiveness. It is our understanding that Non-Tradable/Non-Us eable allocations will be issued to emitters, and that these “safety valve” allocations can be used as compliance instrument when the average cost of annual NOx RTC exceeds $15,000 per ton (or $7.50 per pound). However, we believe that the time for cost averaging should be significantly shortened to prevent the repeat of situation similar to year 2000 when the value of annual NOx RTC went far above the $7.50 per pound threshold. Also, additional safe guards should be consid ered to prevent non-compliance for non-BARCT sources if the NOx RECLAIM market fails such th at no NOx RTCs are available to be purchased. Response 9-1 The comment expresses concerns about the effect of the shave on a facility, such as Eco Services that does not have equipment subject to BA RCT. Staff appreciate s your comment and acknowledge all your efforts in reducing SOx e missions with the installation of the wet gas scrubber at your facility. We be lieve that if BARCT reductions are achieved in 2022, there should still be a comparable margin in the market between the allocation cap and the actual emissions as there is today. The current market has about a 28% margin, while in 2022 the market should have about a 23% margin if BARCT controls are insta lled. The implementation sc hedule is over several years, so the full magnitude of the shave would oc cur gradually. As the allocation cap decreases, the price of RTC is expected to rise. Despite this, there is a safety valve that would allow for more RTCs to be accessed in the event that the 12-m onth rolling average threshold price trigger is reached. The commenter also has concerns of the financial impact to facilities facing a similar situation. Please refer to the socioeconomic repo rt. The commenter also makes reference to a

### 323 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 prior comment letter submitted on April 27, 2015 which refers to the price of purchasing credits based on the current market value. We acknowle dge that at the current price of credits of around $100 per pound, the cost of purchasing credits after th e shave to offset annual emissions would be in the neighborhood of $2.6 million for your facility. Your facility is included as part of the shave because it is among the top 90% of RTC holders and the RECLAIM program will have some structural buyers.

### 324 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #10 – Charles Timms, Jr. Letter Dated September 17, 2015
Comment 10 - 1

Response 10-1

### 325 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The commenter has suggested that additional rule language be adde d to ensure that unused RTCsfor emissions compliance from electric generating facilities are submitted into the SIP on a yearby-year basis. The proposed rule language establishes the mechanism by which the non-tradable and Regional NSR accounts are handled. The non-tradable account is the yearly shaved amount of RTCs. The rule language states that after one full compliance year the credits will be submitted into the SIP. For the first year of the shave, the non-tradable account can be accessed if the 12- month rolling average threshold price trigger is reached or if there is a State of Emergency. For electric generating facilities with continual NSR requirements, th e non-tradable balance can be used for NSR holding purposes, and subsequen tly will become the portion that will fund the Regional NSR account for the same purpose. Howe ver, the RTCs may be used for compliance with annual emissions and will become usable if the price trigger is reached or a State of Emergency is declared. Existing electric generating facilities will also have access to their nontradable/non-usable RTCs in a State of Emergenc y, as well as the Regional NSR Holding Account. If the non-tradable account is accessed, the following year’s permit will be adjusted accordingly. The commenter also provided some suggested rule language that echoes the same comments from the previous comment letter regarding the designat ion of a State of Emergency by someone other than the Governor. As stated in the response to comment 7-5, the safety valves that are proposed by staff are sufficient to ensure that there will be available credits in the event of either a shortage of credits or a major power crisis as declaredby the Governor. Sta ff does not support allowing the Reliability Coordinator to dictate access to the Regional NSR account because an “alert” is not a true State of Emergency requiring extraordinary measures.

### 326 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment Letter #11 – Southern California Edison No Date
Comment 11-1

Response 11-1 The commenter states that there will be cost impacts to electricity generating facilities when there is no reduction in emissions from these sources. While we recognize that most of the equipment used by the electric generation sector is at BARCT or BACT, the proposed shave affects the top 90% of RTC holders and is necessary to obtain the highest amount of feasible reductions to meet SCAQMD’s attainment goals. Note that most electricity generating facilities hold a significantly more RTCs than their actual emissions, and that staff is proposing resolution language to monitor trends in electricity demand and propose program adjustments if necessary. The staff proposal has several safety valves that can address certain issues that are specific to the electrical electricity generating sector, such as relief fro m yearly NSR holding requirements.
Comment 11-2

### 327 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Response 11-2 The commenter states concerns with a potential shortage of credits as a result of the shave. As stated in the previous response, there are safety valves in the current rule and also in the rule proposal that would prevent this condition from occurring. For example, existing electric generating facilities would have access to non-tradable credits in the event that the 12-month rolling average threshold price trigger is reached or if a State of Emergency is declared. New electric generating facilities (i n RECLAIM after October 15, 1993), would have access to a Regional NSR Holding Account to relieve them of NSR holdings re quirements that often require holding excess credits at the poten tial to emit level, even though th e actual emissions are far below this level. In addition, in the event of a powe r emergency, all electric generating facilities would have access to the Regional NSR account for cred its used to offset these emissions during an emergency. Comment 11-3

Response 11-3 The comment states that access to additional credit s should be realized in a faster timeframe for unforeseen situations where emergency power ge neration may be necessary. Non tradable/nonusable RTCs are proposed to be accessed immediately if a State of Emergency is declared. Please

### 328 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 refer to the response to Comment 11-2. Despit e this, a facility would still have some time to reconcile all of its emi ssions at the end of a compliance year quarter, plus the reconciliation period.
Comment 11-4

Response 11-4 The comment requests additional time for the extension of postponed RATA testing from 14 operating days to 30 operating days. The operating da ys do not have to be consecutive days so the total calendar days since the re-firing c ould be longer than 14 consecutive days.

### 329 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment 11-5

Response 11-5 The comment expresses the support for the establ ishment of the Regional NSR Holding Account. We appreciate your support for these provisions a ffecting newer electric ge nerating facilities with burdensome NSR holding requirements.

### 330 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #12 – GE Capital & Inland Empire Energy Center Letter Dated September 22, 2015
Comment 12-1 Inland Empire Energy Center, LLC, a wholly-ownedsubsidiary of General Electric (GE), is the permit holder for the Inland Empire Energy Center (IEEC). GE purchased all NOx RTCs required for the IEEC instead of having them purchasedby IEEC, LLC. The GE RTC account is, and always has been, 100% dedicated to the IE EC. Thus GE’s NOx RRTC account should be designated as an Electric Generating Facility (non- refinery) account for purposes of the allocation shave. We therefore request that the GE RT C account be correctly categorized as an Electric Generating Facility (non-refinery) account in Ta ble 8. Currently, GE is categorized as an “investor”. Response 12-1 The comment requests for the Investor account th at is associated withInland Empire EnergyCenter only to be categorized as an electric generating facility subject to the shave for the nonrefinery sector. SCAQMD staff has reviewed the information you submitted and we agree that the investor account is associated with this el ectric generating facility only. The updated list of facilities will reflect the categorization of the investor account as a facility among the electric generating facilities affected by the shave. Tabl e 8 of Rule 2002 will also be updated to reflect this change.

### 331 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Comment Letter #13 Comment 13-1 The Shave for the Prog ram Should be a Minimum of 14.85 tpd We do not agree with the decision to reduce th e total shave amount by 0.85 tpd, from the required 14.85 tpd to 14 tpd. California’s Health & Safety Code is abundantl y clear that trading programs must “result in an equivalent or greater reduction in emissions at e quivalent or less cost compared with current command and control regulations. . . .” Cal. Health & Safety Code §39616. In reviewing the materials produced through this rulemaking, the Best Available Retrofit Control (“BARCT”) assessments show th at a BARCT-equivalent program would result in 14.85 tpd fewer emissions. Accordingly, to comply with Health& Safety Code section 39616, the shave for the RECLAIM program must also be at least 14.85 tpd. We also suggest shaving even more from the program given the large size of the “black box” th at must be reduced to meet ozone standards. Response 13-1 SCAQMD staff understands the commenter’s request for as many reductions as possible to be able to meet the attainment goals of the region. Th e reason that the overall RTC reduction is 14 tons per day and not more is to account for some BARC T uncertainties that arose in the refinery boiler and heater category. Staff and the consultant hired to do an independe nt BARCT assessment had some reasonable, but different engineering and co st assumptions which resulted in an adjustment to the staff proposal to account for this uncertainty. Comment 13-2 The Implementa tion Schedule is Weak We are deeply concerned that the schedule for implementation for the shave is too protracted. See Slide 4 of the Staff Presentation. Given recent difficulties in mee ting various air quality standards, including the 1997 and 2006 standards for fine particle pollution (“PM2.5”), it would be prudent to move up some of the latter ye ar reductions. In fact, we sugges t amending the schedule to the following to ensure reductions on the front end in time for compliance with Standards: 2016: 5tpd, 2018: 3 tpd, 2019: 3 tpd, 2020: 2 tpd, 2021: 1.85 tpd. Response 13-2 Staff agrees with front loading some of the RTC reductions and has proposed a 4 ton per day reduction in 2016. The implementation schedule serv es two purposes. The first is to address the SIP commitments to EPA regarding the contingency measure for 2016. The second is to ensure facilities have adequate time to install controls if that is how they choose to comply.
Comment 13-3 The District Should Not Establish a NSR Set Aside Health Advocates do not support the implementation of a District-operated set-aside for New Source Review (“NSR”) holdings. There is no basis fo r the District to undertake this task. In fact, this provision exists to ensure the program does not erode air quality progress in the region. We think this is a necessary safeguard, and we have not heard a compelling reason why the District should take on this duty. Industries have complie d with this provision for decades, and it makes sense to continue to place this duty on industry.

### 332 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015

Response 13-3 The commenter disagrees with the staff proposal to offer the Regional NSR Holding Account for electrical electricity gene rating facilities. The staff proposal a ims to reduce the total allocation of the RECLAIM universe by over 53%. This is a ve ry substantial reduction, much more so than the 22.5% reduction that resulted from the 2005 ame ndments to RECLAIM. Electrical Electricity generating facilities are in a unique situation in th at they are all at either BARCT or BACT. In addition, the newer electric generating facilities have to meet the NSR holding requirements every year at the potential to emit level, even though th e actual emissions are far below this level. While the staff proposal will shave thos e electric generating facilities am ong the top 90% of RTC holders by 49%, the Regional Account would provide so me relief from their NSR holding obligations and help to maintain a functioning market in the ev ent of a power emergency. This Regional Account would account for a small fraction of the overall proposed RTC reduction, which is designed to achieve BARCT-equivalent levels of emissions across the program.
Comment 13-4 The California Environmental Quality Act Analysis Should Examine a Command and Control Alternative It is important that the Governing Board and the public receive full information on the environmental landscape of this ac tion. In particular, through the California Envir onmental Quality Act (“CEQA”) process, an assessment of a Command and Control alternative will be important to understand how quickly desperately needed reducti ons could be implemented in the South Coast under a regulatory program requiring implementati on of readily available technologies, many of which have not been installed at the largest NOx emitters in the South Coast. Under the currently proposed approach, clean up would be protracted for many years as the shave is implemented. A Command and Control Alternative would achievereductions sooner than this compliance schedule. Response 13-4 The commenter requests that a command and contro l alternative should be evaluated by CEQA. The purpose of the RECLAIM program is to allow emission reductions equi valent or greater to command and control at an equivale nt or less cost. The BARCT analysis analyzed the technologies available to effect emission reductions that are cost effective and that are in compliance with the California Health and Safety Code. The actual co ntrol technologies to meet BARCT would be the same under command and control as assumed in the Project in the CEQA document, so the environmental impacts would be the same.
Comment 13-5 The claims of industry lobbyists that the IYB credits are appropriately pricedare not true. In fact, like the short term credits, these credits are exceptionally low. Even with a more than doubling of the IYB prices in 2014 compared to 2013, these credits are only 18% of the $609,187 cost established by the District pursuant to secti on 39616(f) of the California Health & Safety Code, which is set to ensure credit prices do not go too high. That the failure of these IYB credits to even

### 333 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 approach 1/5 of the District’s ceiling for credit costs just bolsters the excessive number of credits in the NOx RECLAIM system. Overall, the evidence conclusively suggests that the credits are not priced correctly to push for pollution reductions at a level commensurate with what command and control would achieve, which is borne out in the District’s BARCT assessments. Response 13-5 Comment noted. Comment 13-6 The Shave Appr oach Must Ensure Reductions from Refineries and Electric Generating Facilities. The evidence presented by the District in this rule making indicates that re fineries have used the NOx RECLAIM system as a shield from actually installing pollution control equipment like Selective Catalytic Reduct ion (“SCR”). Given this past behavior, we suggestthat the best path forward is that refineries be taken out of th e NOx RECLAIM program and be required to install pollution control equipment. Response 13-6
The comment states that refine ries should be removed from the RECLAIM program to force the installation of control equipment. As stated inthe previous comment, the staff proposal is for a 53% overall RTC reduction from the RECLAIM univer se. The refinery sector would experience a 66% RTC reduction. Staff believes that there is a sufficient impetus in the staff proposal to effect cost effective control technology installations at these facilities.

### 334 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #14 Arnie Smith Email Dated August 11, 2015
Comment 14-1 At this point, we are probably one to two months aw ay from having finalized NOx RECLAIM rules. Then, we are only another two months from the beginning of the first compliance year. There will be inadequate time for project development with any results in 2016/2017 - even for simpler scopes like burner replacements in existing heaters or catalyst upgrades in existing SCRs. But, new scrubbers or new SCRs would not be able to provide any mitigation benefit until 2018/2019. The ongoing SOx RECLAIM Program had a gap of 26 months from the end of rule-making to the beginning of compliance - which would allow for some mitigation to be realized in the first compliance year. A three year gap would have insured an even stronger result. A three year gap between rule-making and the fi rst compliance year for NOx RECLAIM would have provided a better start for a real NOx reduction. Response 14-1 The commenter expresses his concern that the proposed implementation schedule for the shave would provide inadequate time for projects to be completed and provided a reference to a document from the Association for the Advancement of Cost Estimating (AACE) that many engineering, procurement, and construction (EPC ) firms use for designing their projects. The commenter uses the reference to illustrate that it takes many months of lead time and up to two to three years for emission reduction projects to be in stalled. Staff understands that there is a lead time associated with any construction project, but believes that the initial 4 ton per day reduction in 2016 would be satisfied by removing unused RTCs while still being able to provide the market with sufficient credits until further reductions in the allocation cap are realized. There is currently about a 28% margin from the allocation cap and the actual emissions. With a 4 ton per day reduction, it is anticipated that there would still be sufficient credits in the market to cover actual emissions. By 2018 when the next portion of the sh ave will be effective, several smaller projects would likely be installed, so when 2019 is reache d, those larger projects that the commenter has referred to would be in place and would re sult in emissions under the allocation cap.

### 335 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #15 Karl Lany Email Dated August 20, 2015
Comment 15-1 Thanks for taking the steps you have to accomm odate Rule 219 boiler technology into the proposed RECLAIM amendments. After giving the concept more consideration, I c ontinue to question the proposed requirement that such boilers be subjec t to testing requirements in order to qualify for RECLAIM reporting factors that reflects certification standards. The entire SCAQMD program for certified diesel engines rests upon certification standards and excludes any emissions testing. It makes sense thatthe benefits of certif ication (exclusion from unnecessary emissions tests) that are extended to process unit diesel engines in RECLAIM would also be extended to permit exempt natural gas boilers that are subjected to a similar certification program. I sincerely hope that SCAQMD reconsiders its pr oposed testing requirements for Rule 219 boilers in RECLAIM and instead provides a more practical solution that reflects the legitimacy of its boiler certification program. Response 15-1 The commenter requests a reconsideration of the source testing requirement s of small, unpermitted boilers in the staff proposal for usage of a lowe r emission factor for reporting Rule 219 equipment emissions. See Response 6-2.

### 336 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #16 George Pian tka Email Dated August 14, 2015
Comment 16-1 In Rule 2005, will there be proposedlanguage to address annual holding limit requirements for a facility like Walnut Creek? Response 16-1 The comment asks for proposed language for the affected facility. Staff is proposing to list the actual NSR holdings going into the Regional account year by year in Rule 2002 for those affected facilities. On the facility RECLAIM permits, Section B would still contain the usable/tradable and non-usable/non-tradable amounts, but the Regional account holdings will refer to the Rule 2002 as part of the permit conditions.
Comment 16-2 The financial impact to a new facility like Walnut Creek is different than an existing RECLAIM facility or new plant at an existing RECLAIM facility. In satisfying NSR (unlike a legacy RECLAIM facility), IYB Cycle 1 and 2 RTCs were purchased from the market. Demonstration that we satisfied the RTCs for annual NOx PTE wa s not only necessary for the Permit to Construct and annual Permit to Operate but also for the financing of the WCEP. We would now represent that the asset has lost the equivalent of 47% of its NOx IYB RTCs at the current rate of say $115/lbyr and address the means to which we can demo nstrate our continued holding and/or access to these RTC for the lenders. While not obvious, the fi nancial implications are di fferent than a facility that has relied on an existing RECLAIM account or the ability to reconcile its emissions for the respective year. It is the difference between losi ng the unrealized value of IYB RTCs in a legacy RECLAIM account versus the purchase, shave and po ssible replacement of th em at the new market condition (or from the Regional NSR Holding Account?) to meet its PTE. This is one of the reasons why we believe WCEP should be exempt from the shave. Response 16-2 The comment expresses concerns with the shave and its effect on a new facility that will continue to have NSR holding requirements every year. Staff acknowledges this situation for new electric generating facilities and the proposal includes provi sions that would provide some relief for the NSR holding requirements with the establishm ent of the Regional NSR Holding Account.

### 337 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #17 Chuck Casey Email Dated September 24, 2015
Comment 17-1 The list as provided in table U.1 needs to be audi ted with a full explanation of who is included or excluded and the reason for each. The NOx sh ave percentage adjusted for non-refinery RTC holders’ weighted reduction, currently 47%, woul d require adjustment if the list changes. Response 17-1 The commenter requests for a clarification on wh ich electric generating facilities are part of the proposal for the shave and if cogeneration faci lities are to be considered electric generating facilities for inclusion in the shave. SCAQMD st aff has taken your commen ts into consideration and acknowledges that all electri c generating facilities were included into the shave, even those under the 90% RTC Holders cutoff so that those w ith NSR holding obligations would be able to use the Regional NSR Holding Account. Upon fu rther consideration, st aff has removed those electric generating facilities that are under the 90% cutoff for RTC holders from the list of facilities for the shave.

### 338 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #18 Los Angeles Department of Water and Power Dated August 14, 2015
Comment 18-1 The commenter feels that since its facilities are already at BARCT/BACT, cannot reduce power production to meet demand if there are no credits av ailable, and could face a potential increase in NOx emissions due to transportation electrificati on, the current rule language for the conversion of non-tradable/non-usable RTCs to non-tradable/usable is in equitable and costly. LADWP recommends an alternative approach applicable to electrical electricity generating facilities such that the non-tradable/non-usable RTCs c ontinue to be deemed non-tradable, but usable for compliance without the price threshold trigger. Response 18-1 SCAQMD staff has taken these comments into c onsideration and has pr oposed a mechanism for accessing non-tradable/non-usable credits and also credits in the Regional NSR Holding Account with associated triggers. For the first year of the shave, the entire non-tradable/non-usable portion of a facility may be accessed if the rolling 12-month RTC price exceeds $22,500/ton. Those credits would become usable and tradable. The non-trad able/non-usable credits and the Regional NSR holding Account could also be accessed if the Governor of California declares a State of Emergency related to electricit y demand or power stability in the Basin, but would be usable/nontradable. Over time, the amount of RTCs in the Regional NSR Holding Account increases, and staff is not proposing a charge for use of these credits in the event of a power generating emergency declared by the Governor. Staff is considering additional provisions for a fa ster responding price trigger to access the nontradable/non-usable RTCs. Staff is also developing Governing Board adoption resolution language to direct staff to track the effects of increased electrification of transportation and penetration of renewabl e power sources on the electricity market, and report to the Stationary Source Committee annually with recommendations for program adjustments, if necessary. These market safeguards will ensure that electrical electricity generating facilities have access to credits in the event of a power emergency without the curtailment of power, while also providing an alternative for these facilities to no longer participate in a market program. Staff is proposing rule language that would allow electrical electricity generating facilities whose equipment is at BACT or BARCT to opt out of the RECLAIM prog ram. This would subject electrical electricity generating facilities to Command and Control rules.
Comment 18-2 LAWDP recommends that the 2022 NOx RTCs for power producing facilitie s not be submitted for inclusion into the State Implementation Plan in order to serve native load customers and anticipate future increased electrical demand. Response 18-2 The commenter provides recommende d alternative rule language for Proposed Rule 2002 (f)(1)(J) to not require RTCs reduced from electrical electricity generating facilities to be submitted into the SIP. The proposed rule language establis hes the mechanism by which the non-tradable and Regional NSR accounts are handled. The non-tradab le account is the yearly shaved amount of

### 339 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 RTCs. The rule language states that after one full compliance year the credits will be submitted into the SIP. For the first year of the shave, the non-tradable account can be accessed if the 12- month rolling average threshold price trigger is reached or if there is a State of Emergency. Existing power plants will also have access to th eir non-tradable/non-usable RTCs in a State of Emergency, as well as the credits in the Regi onal NSR Holding Account for subsequent years of the shave. Staff believes these safeguards would provide electrical electricity generating facilities with RTCs to meet their demand needs. In add ition, staff is proposing to add language to the adoption Resolution directing staff to track the effects of increased electrification of transportation and penetration of renewable power sources on the electricity market , and report to the Stationary Source Committee annually with recommendations for program adjustments, if necessary. The RTCs in the Regional Holding Acc ount will not be submitted in the SIP, and thus, if needed and with future rule amendments, could potentially be used to offset NOx emissions due to increased demand for electricity over the long term. Staff fe els that this approach will provide the necessary program safeguards in lieu of not submitting the RTCs resulting from the 2022 NOx adjustment factors for electrical electricity generating facilities into the State Implementation Plan. Otherwise, the potential emission reductions represented by thes e RTCs could never be used for demonstrating attainment of the ozone or PM2.5 NAAQS, even thoug h they may not be needed to offset actual emissions.
Comment 18-3 Electrical Electricity generating facilities’ ability to access RTCs in the Regional NSR Holding Account (formerly Adjustment Account) for the pu rposes of compliance is constrained due to the State of Emergency declaration. The rule languagesuggests that the RTCs in this account are limited after NSR requirement s are met. This introduces great uncertainty whether there will be sufficient RTCs in this account. There are instances when LADWP must have its generating units available for operation in a short time frame to adjust to rene wable production volatility. A “Reliability Coordinator” should have the authority to declar e the State of Emergency and determine the distribution of RTCs . In addition, the staff report should explicitly state that the Regional NSR Holding Account RTCs would not besubmitted to the State Implementation Plan. Response 18-3 The comment expresses concerns on how the Re gional NSR Holding account would function for electrical electrici ty generating facilities during a State of Emergency. The proposed rule language provides the mechanism by which access to these RTCs are given. Under a State of Emergency declaration, the current compliance year non-tradabl e/non-usable NOx RTCs may be used to offsetemissions after exhausting the tradable/usable RTCs. If a facility has exhausted its nontradable/usable RTCs, it may apply for the use of RTCs in the Regional NSR Holding Account. The facility requesting RTCs from the Regional account would submit a written request to the Executive Officer specifying the amount of RTCs needed. The Executive Officer will determine the amount and distribution of the RTCs from the Regional account based on certain criteria specified in the proposed amended rule. If ther e are not enough RTCs for all the power plants requesting relief, the RTCs will be distribut ed proportionately. These RTCs would be nontradable, but usable to offset emissions, and thus not be submitted into the SIP. The commenter also states that it may not be appropriate for the Executive Officer to determine the amount and distribution of RTCs and thereby make the determination of which power plants

### 340 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 would generate electricity during a State of Emer gency. Given the quart erly reconciliation period, staff believes there will be sufficient time and available RTCs for the Executive Officer to make findings and distribute RTCs to facilities soon after a short term power crisis. If the crisis is prolonged, there will be time to propose program adjustments and/or rule amendments to the Governing Board. Staff believes that a major power crisis would warrant a State of Emergency declaration and not just an elevation in power demand. Staff understands that there are other factors to consider, such as the increase in the electrification in the transportation sector that may cause the demand to rise, as the commenter stated. Combined with the less er amount of RTCs available as a result of the shave and higher resultant RTC prices, electrical electricity generating facilities may need some relief to gain access to more RTCs. Staff feels that the safety valves in the proposed amendment would address these concerns. Nonetheless, staf f proposes to add resolution language to monitor the power-producing sector for trends in power consumption and associated NOx emissions as electricity demand potentially increases. If th e State of Emergency is prolonged, the proposed amendments provide for a report to the Governing Bo ard after any power crisis trigger such that a plan for distribution of RTCs and possible progra m adjustments can be made before the supply of emergency RTCs is exhausted. The comment lastly states that the staff report should explicitly state that the RTCs in the Regional NSR Holding Account will not be submitted to the SIP. Both the rule language and the draft staff report state that these RTCs will not be submitted to the SIP.
Comment 18-4 LADWP recommends that the description “Gas Turbines” under the Nitrogen Oxides Basic Equipment column be amended to read “Refinery Gas Turbines” to distinguish that the Power Producing Facility gas turbines are not subject to BARCT in this rule amendment process. Response 18-4 The commenter requests an amendment to the equipment description for gas turbines in Table 6 of proposed amended rule 2002. As part of the BA RCT analysis, gas turbines in both the refinery and non-refinery sectors were analyzed for BARCT. In particular, there are some gas turbines in the non-refinery sector which produce power that ar e subject to BARCT. Thus, the description in Table 6 is broader than “Refinery Gas Turbines.” The turbines at the electrical electricity generating facilities that the commenter refers to are not subject to BARCT because most of the units already operate at BACT, and this distinctio n is made in Appendix Q of the draft staff report that contains the BARCT analysis. Note that the amount of the reductions calculated for the proposed shave did not include any of the units th at were already at or below the BARCT level.
Comment 18-5 The 14 operating day window for conducting a postponed RATA is insufficient. LADWP also requests that the clarification in the preliminary dr aft staff report that states that the proposed 14 operating day RATA postponement would apply separately for each unrelated, independent event also be placed in the rule language. Response 18-5

### 341 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The commenter had experienced multiple sequential failures to a unit which prompted the comment. Staff agrees that each unrelated independent event that rendered a major source incapable of operating separately qualifies fo r a postponement under this provision. Staff has revised the proposed rule to make this explicit. Th e commenter verbally expressed that this change satisfactorily addresses the conc ern regarding the length of timefor conducting a RATA after the source is returned to service.
Comment 18-6 LADWP suggests that the semi-annua l or annual assessment be allowed to be delayed even if the RATA was scheduled during the second 45 days of the calendar quarter in which the assessment was due, instead of being scheduled during the firs t 45 days of the calendar quarter as the current rule proposes. Response 18-6 The operations of electrical electricity generating facilities are highly dependent on demand. RATA testing should be scheduled at the first opp ortunity available. Due to the unpredictability of electric demand, the sc hedule for operations is s ubject to change and actual operations that allow for RATA testing may not occur throughout an entire quarter. In those circumstances, the facility operator has exercised reasonable diligence in atte mpting to comply with RATA requirements, but failed to due to circumstances beyond its reasonabl e control. Therefore, the exemption is only offered in these cases. It is unreasonable to allo w delay in conducting RATAif a facility operator decided to wait until the last part of the quarter to try and schedule a RATA. Staff explained this viewpoint to the commenter who has verbally accepted the reasoning.
Comment 18-7 The proposed requirement to disconnect and flange the fuel feed lines when a unit is physically incapable of operation and maintainoperational fuel meters introduc es health and safety issues, compromises structural integrity of the pipelines and would be costly at steam generating units scheduled to be replaced. Response 18-7 SCAQMD staff discussed this issue with the commenter and agreed to incorporate language similar to the suggested language. The revised language did not make it into the version that was released October 6, 2015 but will be incorporatedinto the proposed amended rule that will be considered by the Governing Board.

Comment 18-8 LADWP presents a completely diff erent alternative regulatory approach for consideration, which involves a credit mechanism by wh ich electrical electricity generating facilities would have access to RTCs to support native load and transportation electrification. Two whitepapers are attached that detail this alternative approach and crediting mechanism, in addition to suggested resolution language addressing increased transportation el ectrification. Tradable RTCs would serve to address native load, and non-tradable RTCs would be allocated to cover increased generation due to mandatory and non-mandatory el ectrification measures. The tradable RTCs would not be adjusted, while the non-tradable RTCs would be ad justed to reflect the actual increased demand.

### 342 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 The SIP crediting mechanism is based on a similar approach that EPA has developed to incorporate energy efficiency and renewable energy strategies into SIP attainment strategies, which involves a quantification of NOx emissi on reductions that would beachieved from basin-wide electrification and a quantification of NOx emission increases from electrical electricity generating facilities to support this electrification. Response 18-8 The commenter has presented an alternative appr oach, with supporting enclosures, which would address the increase in transportation electrification and the associated increase in electrical demand and NOx emissions. The framework of this mechanism, in part, involves the consideration of control measures for attainment strategies as part of the State Implementation Plan. The approach of the commenter’s strategy is outside th e scope of this rule making for RECLAIM. As detailed in the previous responses to this co mment letter, the staff proposal outlines market safeguards that will help to address any possible market upset due to a shortage of credits, high RTC prices, and the potential increase in electrific ation basin-wide. The objective of the proposed project is to fulfill the obligation of 2012 AQMP control measure CMB-01, which is a reduction of RTCs from the NOx RECLAIM market based on a BARCT analysis. Under the staff proposal, if every unit subject to BARCT would install cont rols, there would still be a sufficient margin of credits available, comparable to the margin that exists today between the allocation cap and actual emissions. To attempt to quantify the anticipated increase in electrical demand due to the electrification of the transportati on sector today would be specul ative. The staff proposal has provided additional safeguards, such as the threshol d price trigger for access to non-tradable RTCs and access to the Regional NSR Holding Account in the event of a major power emergency. The commenter’s suggested resolution language has been noted and resolution language will be prepared that directs staff to monitor the power-producing sector for trends in power consumption and associated NOx emissions as electricity demand potentially increases.

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### 343 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 Comment Letter #19 Shell Energy North Americ a (US), L.P. Letter Dated August 6, 2015
Comment 19-1 To meet the proposed amendments, the facility woul d need to make significant modifications to the SCR, CO catalyst, and to the exhaust modules housing the catalyst, far exceeding typical cost benefit ratios. The alternative emissions reduc tion choice would be to replace the combustor on the gas turbine, also cost prohibitive. There is no further cost effective NOx reduction technology for this facility. The only way that that such facilities can comply with the current proposed rule is to purchase additional NOx RTCs. This represents a significant expense for generating facilities especially considering the current market co nditions in California, including the recent decommissioning of San Onofre Nuclear Generatin g Station. We request that SCAQMD consider that peaking generation facilities with lower capacit y factor built to BACT should not be obligated under the proposed rule to make further emissi ons reductions, and allow the emissions offsets previously procured for the unit to meet current and future SCAQMD requirements. Response 19-1 The comment requests that the facility in questi on should not be required to make further emission reductions and allow the use of NSR offset credits to meet current and future SCAQMD requirements. The staff proposal includes facilities that hold credits that are in the top 90% of all the RTC holders in the NOx RECLAIM universe. Since this facility is among those facilities in the top 90%, it would be subject to a shave of 49%. A peaking facility such as the one the commenter is referring to is in a similar situation as other electrical electricity generating facilities that are subject to NSR requirement s, have emissions that are far below what they need to hold for NSR purposes, and have RTC holdings that significantly exceed their actual emissions. It is for this specific purpose that the Regional NSR Hold ing Account was created to assist in facilities meeting their NSR obligation without going to the market to purchase credits. As explained in the proposed rule language and in other responses to comments, a newer electrical el ectricity generating facility subject to NSR holding requirements would have the shaved credits put into the Regional account, and the exact quantities are listed for each of the affected facilities in Table 9 of Rule 2002 for every year of the shave. It is not ex pected that such facilities install further controls since most the equipment is already either at BA RCT or BACT. The proposed rule has safeguards that can make non-tradable credits and Regiona l NSR Holding Account credits available under certain specific conditions in the event of an unstable market or in a major power emergency. Staff is also proposing rule language that would al low electrical electricity generating facilities whose equipment is at BACT or BARCT to opt out of the RECLAIM program. This would subject electrical electricity generating facilities to Command and Control rules.

Comment 19-2 We believe that the Date of Am endment (the date that RTC holdi ngs will be adjusted (should be set closer to or upon the actual date when the final Rule is published. Additionally, it is not clear how the March 20, 2015 date was es tablished and does not addres s how NOx RTCs that were transferred between March 20, 2015 and the date of implementation of the Proposed Rule will be

### 344 Draft Final Staff Report – NOx RECLAIM October 6November December 4, 2015 treated. We request that the SCAQMD act pros pectively; the NOx RTC holdings should be the quantity as of the date of the imp lementation of the Proposed Rule. Response 19-2 The commenter requests that the freeze date of th e RTC holdings be changed to the date of the rule implementation. Staff has revised the proposal and notified the stakeholders regarding the proposed new freeze date of September 22, 2015. Staff cannot practically make the freeze date for shave estimation the date of rule adoption becau se the rule language and calculation of shave must be completed for public review and comment prior to the Governing Board hearing for rule adoption. Note that the March datewas retained for determining which facilities were in the top 90%, but the freeze date was chan ged due to stakeholder input.

Comment 19-3 Additional information and clarif ication is needed regarding the Proposed Regional NSR Holding Account for Generators PAR 2000 (f) (4).
Response 19-3 The commenter requests additional clarity and information regarding the Regional NSR Holding Account for newer electrical electricity generating facilities subject to NSR holding requirements. The proposed rule language has been revised to provide clarity as to how the Regional account will be funded and accessed. Table 9 in Rule 2002 contains the list of affected facilities with NSR holdings with a yearly balance of RTCs that will go into the account. Further discussion regarding the proposed amendments is contained in Appendix X of the draft staff report.