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 Development, and Area Sources 

Philip M. Fine, Ph.D. 

Assistant Deputy Executive Officer 

Planning, Rule Development, and Area Sources 

Jill Whynot 

Planning & Rules Director 

Planning, Rule Development, 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 Counsel 
Acknowledgement 

The authors would like to thank the following staff members for providing information for and 

participating in this project: 

Planning, Rule Development & Area Sources 

Elaine Chang (retired), Shah Dabirian, Elaine Shen, Priscilla Hamilton, Ian MacMillan, Barbara 

Radlein, James Koizumi, Ali Ghasemi, 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 Chen, Rezvan Ramezani, George Haddad 
Table of Contents

EXECUTIVE SUMMARY........................................................................................................... 1

BACKGROUND .................................................................................................................................. 1

PROPOSED BARCT, EMISSION REDUCTIONS, AND RTC REDUCTIONS.......................................................... 3

PUBLIC PROCESS............................................................................................................................... 7

CHAPTER 1 – BACKGROUND ................................................................................................ 12

LEGISLATIVE AUTHORITY................................................................................................................... 12

NON-ATTAINMENT STATUS .............................................................................................................. 12

CONTROL MEASURE CMB-01 OF THE 2012 AQMP ............................................................................ 13

CURRENT NOX RECLAIM PROGRAM................................................................................................. 14

NOX RECLAIM FACILITIES............................................................................................................... 16

CHAPTER 2 – FACILITY EMISSIONS AND RTC HOLDINGS........................................................ 18

PROJECTED EMISSIONS AND EMISSION REDUCTIONS .............................................................................. 18

AUDITED FACILITY EMISSIONS AND RTC ALLOCATIONS........................................................................... 19

MAJOR NOX SOURCES AT TOP EMITTING FACILITIES.............................................................................. 21

CHAPTER 3 – 2015 PROPOSED BARCT AND EMISSION REDUCTIONS ..................................... 22

PREVIOUS BARCT DETERMINATIONS ................................................................................................. 22

PROPOSED 2015 BARCT ................................................................................................................ 22

CO-BENEFITS OF ENERGY EFFICIENCY PROJECTS.................................................................................... 24

CHAPTER 4 – COSTS AND COST EFFECTIVENESS.................................................................... 25

STAFF’S PRELIMINARY ESTIMATES ...................................................................................................... 25

CONSULTANTS’ ESTIMATES ............................................................................................................... 26

STAFF RECOMMENDATIONS .............................................................................................................. 28

CHAPTER 5 - RTC REDUCTIONS............................................................................................. 31

REMAINING EMISSIONS.................................................................................................................... 31

CALCULATION METHOD FOR RTC REDUCTIONS .................................................................................... 35

REGIONAL NSR HOLDING ACCOUNT FOR ELECTRICAL ELECTRCITY GENERATING FACILITIES............................ 35

STAFF PROPOSAL AND CEQA ALTERNATIVES........................................................................................ 36

CHAPTER 6 – SUMMARY OF THE PROPOSED CHANGES IN RULE LANGUAGE AND DRAFT

PROGRAM ENVIRONMENTAL ASSESSMENT ......................................................................... 40

RULE 2002 (F)(1) – BARCT PROPOSED LEVELS AND RTC REDUCTIONS ................................................... 40

RULE 2002 (F)(4)AND (F)(5) – ADJUSTMENT ACCOUNT AND STATE OF EMERGENCY RELATED TO ELECTRICAL

ELECTRCITY GENERATING FACILITIES ................................................................................................... 43
RULE 2002 (I) – RTC REDUCTION EXEMPTION .................................................................................... 43

RULE 2005 – REQUIREMENTS FOR NEW ELECTRICAL ELECTRCITY GENERATING FACILITIES ............................ 44

OTHER ADMINISTRATIVE AMENDMENTS.............................................................................................. 44

DRAFT PROGRAM ENVIRONMENTAL ASSESSMENT (PEA) ....................................................................... 46

DRAFT FINDINGS UNDER CALIFORNIA HEALTH AND SAFETY CODE ............................................................. 47

PART I – BARCT ANALYSES FOR REFINERY SECTOR ............................................................... 52

APPENDIX A - REFINERY FLUID CATALYTIC CRACKING UNITS ................................................ 53

PROCESS DESCRIPTION..................................................................................................................... 53

EMISSION INVENTORY...................................................................................................................... 54

ACHIEVED-IN-PRACTICE LEVEL FOR FCCU ........................................................................................... 55

CONTROL TECHNOLOGY ................................................................................................................... 57

COSTS AND COST EFFECTIVENESS FOR SCRS......................................................................................... 64

COSTS AND COST EFFECTIVENESS FOR NOX REDUCTION ADDITIVES .......................................................... 68

COSTS AND COST EFFECTIVENESS FOR LOTOX SCRUBBERS ...................................................................... 69

INCREMENTAL COSTS AND COST EFFECTIVENESS ................................................................................... 71

STAFF’S RECOMMENDATION ............................................................................................................. 73

REFERENCES FOR FCCUS.................................................................................................................. 74

APPENDIX B – REFINERY BOILERS AND PROCESS HEATERS ................................................... 77

PROCESS DESCRIPTION..................................................................................................................... 77

EMISSION INVENTORY...................................................................................................................... 78

ACHIEVED-IN-PRACTICE NOX LEVELS FOR BOILERS AND HEATERS ............................................................ 78

CONTROL TECHNOLOGY ................................................................................................................... 78

COSTS AND COST EFFECTIVENESS FOR SCRS......................................................................................... 83

STAFF’S RECOMMENDATION ............................................................................................................. 92

REFERENCES FOR BOILERS AND HEATERS ............................................................................................. 96

APPENDIX C – REFINERY GAS TURBINES............................................................................... 98

PROCESS DESCRIPTION..................................................................................................................... 98

EMISSION INVENTORY...................................................................................................................... 99

ACHIEVED-IN-PRACTICE NOX LEVELS FOR GAS TURBINES ....................................................................... 99

CONTROL TECHNOLOGY ................................................................................................................. 101

COSTS AND COST EFFECTIVENESS ..................................................................................................... 105

STAFF’S RECOMMENDATION ........................................................................................................... 112

REFERENCES FOR GAS TURBINES ...................................................................................................... 113

APPENDIX D - COKE CALCINER ........................................................................................... 116

PROCESS DESCRIPTION................................................................................................................... 116

EMISSION INVENTORY.................................................................................................................... 116
CONTROL TECHNOLOGY ................................................................................................................. 117

COSTS AND COST EFFECTIVENESS ..................................................................................................... 119

STAFF’S RECOMMENDATION ........................................................................................................... 121

REFERENCES FOR COKE CALCINER..................................................................................................... 122

APPENDIX E - SULFUR RECOVERY UNITS/TAIL GAS INCINERATORS ..................................... 123

PROCESS DESCRIPTION................................................................................................................... 123

EMISSION INVENTORY.................................................................................................................... 123

CONTROL TECHNOLOGY ................................................................................................................. 124

COSTS AND COST EFFECTIVENESS ..................................................................................................... 129

STAFF’S RECOMMENDATION ........................................................................................................... 134

REFERENCES FOR SRU/TG INCINERATORS ......................................................................................... 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 ENERGY EFFICIENCY PROJECTS........................................... 155

APPENDIX L – SURVEY QUESTIONNAIRES FOR REFINERY SECTOR ....................................... 157

PART II – BARCT ANALYSES FOR NON-REFINERY SECTOR.................................................... 160

APPENDIX M – CEMENT KILNS ........................................................................................... 161

PROCESS DESCRIPTION................................................................................................................... 161

CURRENT EMISSION INVENTORY ...................................................................................................... 161

CONTROL TECHNOLOGY ................................................................................................................. 162

PROPOSED BARCT LEVEL AND EMISSION REDUCTIONS ........................................................................ 164

COST EFFECTIVENESS ..................................................................................................................... 165

REVIEW OF ETS’S ANALYSIS FOR CEMENT KILNS ................................................................................. 167

REFERENCES FOR CEMENT KILNS...................................................................................................... 169

APPENDIX N – CONTAINER GLASS MELTING FURNACES...................................................... 170

PROCESS DESCRIPTION................................................................................................................... 170

CURRENT EMISSION INVENTORY ...................................................................................................... 170

CONTROL TECHNOLOGY ................................................................................................................. 170

PROPOSED BARCT LEVEL AND EMISSION REDUCTIONS ........................................................................ 171

COST EFFECTIVENESS ..................................................................................................................... 171

REVIEW OF ETS’S ANALYSIS FOR CONTAINER GLASS MELTING FURNACES................................................ 174

REFERENCES FOR CONTAINER GLASS MELTING FURNACES .................................................................... 177
APPENDIX O– SODIUM SILICATE FURNACE......................................................................... 178

PROCESS DESCRIPTION................................................................................................................... 178

CURRENT EMISSION INVENTORY ...................................................................................................... 178

CONTROL TECHNOLOGY ................................................................................................................. 178

PROPOSED BARCT LEVEL AND EMISSION REDUCTIONS ........................................................................ 179

COST EFFECTIVENESS ..................................................................................................................... 179

REVIEW OF ETS’S ANALYSIS FOR SODIUM SILICATE FURNACE ................................................................ 181

REFERENCES FOR SODIUM SILICATE FURNACE..................................................................................... 182

APPENDIX P – METAL HEAT TREATING FURNACES >150 MMBTU/HR.................................. 183

PROCESS DESCRIPTION................................................................................................................... 183

CURRENT EMISSION INVENTORY ...................................................................................................... 183

CONTROL TECHNOLOGY ................................................................................................................. 183

PROPOSED BARCT LEVEL AND EMISSION REDUCTIONS ........................................................................ 184

COST EFFECTIVENESS ..................................................................................................................... 184

REVIEW OF ETS’S ANALYSIS FOR METAL HEAT TREATING FURNACES >150 MMBTU/HR .......................... 185

REFERENCES FOR METAL HEAT TREATING FURNACES >150 MMBTU/HR............................................... 186

APPENDIX Q – NON-REFINERY, NON-ELECTRICAL ELECTRCITY GENERATING FACILITY

STATIONARY GAS TURBINES .............................................................................................. 187

PROCESS DESCRIPTION................................................................................................................... 187

CURRENT EMISSION INVENTORY ...................................................................................................... 187

CONTROL TECHNOLOGY ................................................................................................................. 188

PROPOSED BARCT LEVEL AND EMISSION REDUCTIONS ........................................................................ 189

COST EFFECTIVENESS ..................................................................................................................... 190

REVIEW OF ETS’S ANALYSIS FOR METAL HEAT TREATING FURNACES ABOVE 150 MMBTU/HR .................. 192

REFERENCES FOR NON-REFINERY, NON-ELECTRICAL ELECTRCITY GENERATING FACILITY STATIONARY GAS

TURBINES .................................................................................................................................... 193

APPENDIX R – NON-REFINERY STATIONARY INTERNAL COMBUSTION ENGINES.................. 194

PROCESS DESCRIPTION................................................................................................................... 194

CURRENT EMISSION INVENTORY ...................................................................................................... 194

CONTROL TECHNOLOGY ................................................................................................................. 196

PROPOSED BARCT LEVEL AND EMISSION REDUCTIONS ........................................................................ 196

COST EFFECTIVENESS ..................................................................................................................... 197

REVIEW OF ETS’S ANALYSIS FOR NON-REFINERY STATIONARY INTERNAL COMBUSTION ENGINES ................. 199

REFERENCES FOR NON-REFINERY STATIONARY INTERNAL COMBUSTION ENGINES...................................... 199

APPENDIX S – NON-REFINERY BOILERS >40 MMBTU/HR .................................................... 200

APPENDIX T – SURVEY QUESTIONNAIRES FOR NON-REFINERY SECTOR............................... 201
PART III – RTC REDUCTION APPROACHES ........................................................................... 203

APPENDIX U – STAFF’S PROPOSAL AND CEQA ALTERNATIVES ............................................ 200

STAFF PROPOSAL UNDER CONSIDERATION......................................................................................... 200

TRADABLE/USABLE AND NON-TRADABLE/NON-USABLE FACTORS IN RULE 2002(F)(1)(B) AND (C) ............ 206

REGIONAL NSR HOLDING ACCOUNT................................................................................................. 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

RULE 2002 ................................................................................................................................. 218

RULE 2005 ................................................................................................................................. 222

OTHER ADMINISTRATIVE AMENDMENTS............................................................................................ 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 - SUMMARY OF PROPOSED BARCT (MAY 2015)............................................................................................. 3

TABLE EX. 2 – SUMMARY 2023 RTC HOLDINGS AND 2023 EMISSIONS AFTER BARCT............................................................. 5

TABLE EX. 3 - SUMMARY OF COSTS AND COST EFFECTIVENESS ............................................................................................. 6

TABLE EX. 4 - SUMMARY OF PUBLIC PROCESS................................................................................................................... 8

TABLE EX. 5 - LIST OF PARTICIPANTS ............................................................................................................................ 10

TABLE 1. 1 – AUDITED EMISSIONS, RTC HOLDINGS AND UNUSED RTCS FROM 2009-2013 ..................................................... 16

TABLE 2. 1 - ANNUAL AVERAGE EMISSIONS (TPD) BY MAJOR SOURCE CATEGORY (2023 BASE YEAR) ...........................................18

TABLE 2. 2 - TOP TEN RANKING OF NOX EMISSIONS FROM HIGHEST TO LOWEST (2023 BASE YEAR) ............................................19

TABLE 2. 3 - NOX AUDITED EMISSIONS (2011 COMPLIANCE YEAR) .........................................................................................20

TABLE 2. 4 - NOX EMISSIONS PER SOURCE CLASSIFICATION ....................................................................................................21

TABLE 3. 1 - 2015 PROPOSED BARCT LEVELS AND EMISSION REDUCTIONS ..............................................................................23

TABLE 3. 2 - CO-BENEFITS OF EMISSION REDUCTIONS FOR ENERGY EFFICIENCY PROJECTS ............................................................24

TABLE 4. 1 – INITIAL PROPOSAL - BARCT LEVELS, COSTS AND COST EFFECTIVENESS - REFINERY SECTOR (DECEMBER 2014).............27

TABLE 4. 2 – INITIAL PROPOSAL - BARCT LEVELS, COSTS AND COST EFFECTIVENESS - NON-REFINERY SECTOR (DECEMBER 2014).....28

TABLE 4. 3 - STAFF’S REVISED RECOMMENDATION FOR REFINERY SECTOR (MAY 2015)..............................................................29

TABLE 4. 4 - STAFF’S RECOMMENDATION FOR NON-REFINERY SECTOR (MAY 2015) ..................................................................30

TABLE 5. 1 - REMAINING EMISSIONS FOR REFINERY SECTOR....................................................................................................32

TABLE 5. 2 - REMAINING EMISSIONS FOR NON REFINERY SECTOR (MAY 2015) .........................................................................34

TABLE 5. 3 - STAFF PROPOSAL - AFFECTED FACILITIES AND PERCENT SHAVE ...............................................................................37

TABLE 5. 4 - ALTERNATIVES FOR CEQA ANALYSIS .................................................................................................................37

TABLE 5. 5 - LIST OF FACILITIES AND INVESTORS THAT WOULD HAVE RTCS REDUCED...................................................................38

TABLE A. 1 - 2011 EMISSIONS FOR REFINERY FCCUS ............................................................................................................55

TABLE A. 2 – LIST OF LOTOX APPLICATIONS.........................................................................................................................61

TABLE A. 3 - COSTS AND COST EFFECTIVENESS FOR SCRS (DECEMBER 2014) ............................................................................66

TABLE A. 4 – COMPARISON OF SCR COSTS ESTIMATED BY STAFF AND NEC (DECEMBER 2014)....................................................66

TABLE A. 5 – REVISED COSTS AND COST EFFECTIVENESS FOR SCRS (MARCH 2015)....................................................................68

TABLE A. 6 - COSTS AND COST EFFECTIVENESS FOR NOX REDUCTION ADDITIVES........................................................................69

TABLE A. 7 - COSTS AND COST EFFECTIVENESS FOR LOTOX APPLICATIONS (DECEMBER 2014) .....................................................70

TABLE A. 8 – REVISED COSTS AND COST EFFECTIVENESS FOR LOTOX SCRUBBERS (MARCH 2015).................................................71

TABLE A. 9 – PRESENT WORTH VALUES OF SCRS AND LOTOX/SCRUBBERS FOR FCCUS.........................................................72

TABLE A. 10 – INCREMENTAL COST EFFECTIVENESS OF SCRS AND LOTOX SCRUBBERS FOR FCCUS (MARCH 2015).........................72

TABLE B. 1– TEMPERATURE ZONES AND NOX EMISSIONS OF GREAT SOUTHERN FLAMELESS HEATER.............................................81

TABLE B. 2 – PREDICTED PERFORMANCE OF GREAT SOUTHERN OXY-FLAMELESS HEATER ............................................................82

TABLE B. 3 – COSTS OF SCRS ESTIMATED BASED ON INFORMATION SUBMITTED BY REFINERY ......................................................84

TABLE B. 4 – PERFORMANCE AND COST INFORMATION OF SCRS FOR PROCESS HEATERS FROM REFINERY SURVEY...........................85

TABLE B. 5 - COSTS OF SCRS ESTIMATED BASED ON INFORMATION FROM SCR MANUFACTURERS ................................................87

TABLE B. 6 – COSTS FOR GREAT SOUTHERN FLAMELESS HEATERS ............................................................................................87

TABLE B. 7 - COSTS FOR GREAT SOUTHERN FLAMELESS HEATERS WITH FUEL SAVINGS.................................................................87

TABLE B. 8 - COSTS FOR DUPLEX BURNERS.........................................................................................................................88
TABLE B. 9 - COMPARISON OF NEC’S AND STAFF’S COST ESTIMATES FOR SCRS (DECEMBER 2014) ..............................................91

TABLE B. 10 – REVISED COST ESTIMATES OF SCRS FOR BOILERS AND HEATERS ..........................................................................92

TABLE B. 11 – DETAILS OF COST ESTIMATES FOR BOILERS AND HEATERS...................................................................................93

TABLE C. 1 - 2011 EMISSIONS FOR REFINERY GAS TURBINES/DUCT BURNERS .........................................................................100

TABLE C. 2 – PERFORMANCE OF DLN AND DLE ..................................................................................................................101

TABLE C. 3 – INSTALLATIONS OF CLN ................................................................................................................................103

TABLE C. 4 – COSTS OF SCR AND ASC FOR 83 MW AND 7 MW COGENERATION UNITS...........................................................107

TABLE C. 5 - PROJECTED INCOME GAIN DUE TO POWER INCREASE FOR CHENG LOW NOX .........................................................108

TABLE C. 6 - EQUIPMENT AND INSTALLATION COSTS FOR CHENG LOW NOX ............................................................................109

TABLE C. 7 – PRESENT WORTH VALUES AND COST EFFECTIVENESS FOR GAS TURBINES..............................................................110

TABLE C. 8 - COMPARISON OF STAFF’S AND NEC’S ESTIMATES FOR GAS TURBINES...................................................................112

TABLE D. 1 - 2011 EMISSIONS FOR COKE CALCINER ............................................................................................................116

TABLE D. 2 – COSTS OF LOTOX AND ULTRACAT FOR COKE CALCINER (DECEMBER 2014) ..........................................................120

TABLE D. 3 - COST AND COST EFFECTIVENESS ESTIMATES FOR COKE CALCINER (DECEMBER 2014) ..............................................120

TABLE D. 4 – REVISED COST AND COST EFFECTIVENESS ESTIMATES FOR COKE CALCINER (MARCH 2015) .....................................121

TABLE E. 1 - 2011 EMISSIONS FOR SRU/TG INCINERATORS .................................................................................................124

TABLE E. 2 - LIST OF DYNAWAVE SCRUBBER INSTALLATIONS FOR SR/TGTUS..........................................................................127

TABLE E. 3 - PROCESS INFORMATION AND NOX EMISSIONS FOR SRU/TG INCINERATORS IN SCAQMD ......................................130

TABLE E. 4 – NOX AND SOX PERFORMANCE OF SRU/TG APPLICATIONS IN SCAQMD ............................................................130

TABLE E. 5 – COST INFORMATION PROVIDED BY MECS .......................................................................................................132

TABLE E. 6 – COST INFORMATION PROVIDED BY KNOWNOX ................................................................................................132

TABLE E. 7 - COMPARISON OF SCR COSTS ESTIMATED BY STAFF AND NEC FOR SRU/TGTUS (DECEMBER 2014) .........................133

TABLE E. 8 - REVISED COST AND COST EFFECTIVENESS ESTIMATES FOR SCRS AND LOTOX FOR SRU/TGTUS (MARCH 2015).........133

TABLE K. 1- SUMMARY OF EMISSION REDUCTIONS AND SCHEDULES OF ENERGY EFFICIENCY PROJECTS.........................................156

TABLE M. 1 - 2011 EMISSIONS FOR CEMENT KILNS.............................................................................................................161

TABLE M. 2 - COST EFFECTIVENESS FOR CEMENT KILNS ........................................................................................................166

TABLE M. 3 - ETS REVISIONS TO COST EFFECTIVENESS FOR CEMENT KILNS..............................................................................167

TABLE M. 4 - SCAQMD REVISIONS TO COST EFFECTIVENESS FOR CEMENT KILNS.....................................................................168

TABLE N. 1 - 2011 EMISSIONS FOR CONTAINER GLASS MELTING FURNACES............................................................................170

TABLE N. 2 - COST EFFECTIVENESS FOR CONTAINER GLASS MELTING FURNACES.......................................................................173

TABLE N. 3 - ETS REVISIONS TO COST EFFECTIVENESS FOR CONTAINER GLASS MELTING FURNACES.............................................176

TABLE O. 1 - 2011 EMISSIONS FOR SODIUM SILICATE FURNACE ............................................................................................178

TABLE O. 2 - COST EFFECTIVENESS FOR SODIUM SILICATE FURNACE .......................................................................................180

TABLE O. 3 - ETS REVISIONS TO COST EFFECTIVENESS FOR SODIUM SILICATE FURNACE .............................................................181

TABLE P. 1 - 2011 EMISSIONS FOR METAL HEAT TREATING FURNACES >150 MMBTU/HR ......................................................183

TABLE P. 2 - COST EFFECTIVENESS FOR FURNACES > 150 MMBTU/HR ..................................................................................185

TABLE Q. 1 - 2011 EMISSIONS FOR RECLAIM NON-ELECTRICAL ELECTRCITY GENERATING FACILITY GAS TURBINES .......................188

TABLE Q. 2 - COST EFFECTIVENESS FOR NON-ELECTRICAL ELECTRCITY GENERATING FACILITY GAS TURBINES..................................191
TABLE R. 1 - 2011 EMISSIONS FOR INTERNAL COMBUSTION ENGINES AT TOP 37 FACILITIES ......................................................195

TABLE R. 2 - COST EFFECTIVENESS FOR LEAN-BURN, NON-OCS ICES .....................................................................................198

TABLE S. 1 - COST EFFECTIVENESS FOR NON-REFINERY BOILERS >40 MMBTU/HR ..................................................................200

TABLE V. 1 - 2011 AUDITED EMISSIONS............................................................................................................................213

TABLE W. 1 - COMPLIANCE YEAR 2011 POWER GENERATING SECTOR EMISSIONS....................................................................220

TABLE W. 2 - 2012 POWER GENERATING SECTOR EMISSIONS BASED ON ANNUAL EMISSION REPORTS (AER) FUEL USAGE ............221
List of Figures

FIGURE EX. 1 – AUDITED EMISSIONS AND RTC HOLDINGS........................................................................................................4

FIGURE 1. 2 – AUDITED EMISSIONS AND RTC HOLDINGS........................................................................................................14

FIGURE 1.3 – NOX DISCRETE RTC PRICE VERSUS THRESHOLD .................................................................................................15

FIGURE 1.4 – NOX INFINITE YEAR BLOCK (IYB) RTC PRICE VERSUS THRESHOLD ........................................................................15

FIGURE 1. 5 – DISTRIBUTION OF 20 TPD NOX EMISSIONS (END OF COMPLIANCE YEAR 2011) .....................................................17

FIGURE 1. 6 – DISTRIBUTION OF 26.5 TPD RTC HOLDINGS (END OF COMPLIANCE YEAR 2020)....................................................17

FIGURE A. 1 - SIMPLIFIED SCHEMATIC OF FCCU PROCESS.......................................................................................................54

FIGURE A. 2 - 2011 NOX EMISSIONS AND NOX CONCENTRATIONS FOR REFINERY FCCUS ..........................................................56

FIGURE A. 3 - 2011 NOX EMISSIONS AND FEED RATES FOR REFINERY FCCUS ...........................................................................56

FIGURE A. 4 - EDV SCRUBBER WITH LOTOX APPLICATION......................................................................................................60

FIGURE A. 5 - NITROGEN CHEMISTRY IN THE FCC REGENERATOR .............................................................................................63

FIGURE A. 6 - NOX REDUCTION ADDITIVE REDUCES NOX EMISSIONS BY 60%...........................................................................63

FIGURE B. 1 - REFINERY PROCESSES ....................................................................................................................................77

FIGURE B. 2 - OXY-FLAMELESS HEATER (REFERENCE 17)........................................................................................................81

FIGURE B. 3 – REVISED PWVS OF CONTROL DEVICES FOR REFINERY BOILERS/HEATERS (MARCH 2015) .......................................89

FIGURE C. 1 - GAS TURBINE WITH DUCT BURNER (VICTORYENERGY.COM) .................................................................................98

FIGURE C. 2 - CHENG LOW NOX (REFERENCE 22) ...............................................................................................................102

FIGURE C. 3 - EFFECT OF HOMOGENEITY AND STEAM TO FUEL RATIO IN CLN APPLICATION (REFERENCE 22) ................................103

FIGURE C. 4 - EFFECT OF HOMOGENEITY AND STEAM TO FUEL RATIO ON NOX EMISSIONS IN CLN APPLICATION ...........................104

FIGURE C. 5 - PRESENT WORTH VALUES FOR GAS TURBINES .................................................................................................109

FIGURE D. 1 - COKE CALCINER PROCESS (REFERENCE 1) .......................................................................................................117

FIGURE D. 2 - ULTRA-CAT FILTERS (REFERENCE 5)...............................................................................................................118

FIGURE E. 1 - DYNAWAVE SCRUBBER (REFERENCE 23) ........................................................................................................126

FIGURE E. 2 - OZONE GENERATION PROCESS (REFERENCE 23)...............................................................................................126

FIGURE E. 3 – KNOWNOX PROCESS (REFERENCE 28) ..........................................................................................................128

FIGURE M. 1 - ULTRA CAT CERAMIC FILTER SYSTEM ............................................................................................................163

FIGURE M. 2 - CLOSE-UP OF FILTER HOUSING AND SYSTEM OPERATION (REFERNCE #2) ...........................................................163

FIGURE Q. 1 - NOX CONCENTRATIONS FOR NON-ELECTRICAL ELECTRCITY GENERATING FACILITY GAS TURBINES AT TOP 37 EMITTING

FACILITIES ...........................................................................................................................................................188

FIGURE R. 1 - NOX CONCENTRATIONS FOR LEAN BURN ICES AT TOP 37 EMITTING FACILITIES ....................................................195
AC

AER 

AQMP 

ASC 

Basin 

BACT 

BARCT 

CARB 

CE

CEMS 

CLNTM

CM

CO

CO2

CR

CY

DCF 

DLN/DLE 

DOE

EPA 

ER

ESP 

ETS

o F

FCCU 

GF

HHV

HRSG 

H&SC 

GFIYB 

LCF 

LoTOxTM

NAAQS

NEC 

NO

NO2

N2O

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 Retrofit 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 Program 
RTC RECLAIM Trading Credit 

SCAQMD South Coast Air Quality Management District 

SCR Selective Catalytic Reduction 

SIP State Implementation Plan 

SNCR Selective Non Catalytic Reduction 

SO2 Sulfur Dioxide 

SO3 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 
Draft Final Staff Report – NOx RECLAIM 1

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 Air 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 reductions. The RECLAIM program started with 392 

NOx facilities in 1993. By the end of compliance year 2013, there were 275 facilities in the NOx

RECLAIM universe. 

Best Available Retrofit Control Technology for RECLAIM 

When the NOx RECLAIM program was first adopted, the NOx RECLAIM facilities were issued 

NOx annual allocations (also known 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 Control Technology (BARCT) envisioned 

to be in place at the RECLAIM facilities, and were 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 technology and to ensure that RECLAIM facilities 

achieve the same emission reductions that would have occurred under a command-and-control 

approach and that emission reductions from the program 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 in 2010, 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 ground-level 8-hour ozone standard 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 
Draft Final Staff Report – NOx RECLAIM 2

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 stakeholders 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 RECLAIM is one of the control measures included 

in the 2012 AQMP. Control Measure CMB-01 called 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 reductions 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-refinery sector). For electrical electricity generating 

facilities, staff used 2012 emissions instead of 2011 due to several reasons: 1) local electrical 

electricity generating facilities in the region operated more in 2012 to make up for the closure of 

the San Onofre Nuclear Generation Station (SONGS), 2) the commissioning of new electrical 

electricity generating facilities in the region was reflected more accurately in 2012, and 3) a recent 

shift in the use of renewable energy sources, such as 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 the 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%. 
Draft Final Staff Report – NOx RECLAIM 3

October 6November December 4, 2015 

Proposed BARCT, Emission Reductions, and RTC Reductions 

The BARCT analysis resulted in the BARCT levels and incremental emission reductions by 2023 

shown in Table EX.1. For the refinery sector, a new 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 >150 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 cement facility 

was not in operation in 2011. Cement kilns were the highest emitting stationary source of NOx emissions in 2008, thus staff conducted 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 analyses 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.)
Draft Final Staff Report – NOx RECLAIM 4

October 6November December 4, 2015 

As shown in Table EX.1, the total BARCT-equivalent emission reductions are 8.8 tpd (6.00 tpd 

for the refinery sector and 2.77 tpd for the non-refinery sector.) Due to projected growth,2 the 

remaining emissions in 2023 at these proposed 2015 BARCT levels would be 10.2 tpd (2.76 tpd 

for the refinery sector and 7.47 tpd for the non-refinery sector.) Staff has added a 10% compliance 

margin to the 2023 remaining emissions. In addition, staff has added the remaining emissions 

from shutdown glass and cement facilities at BARCT levels, thereby adding to the compliance 

margin, as well as the emissions for new facilities entering RECLAIM program since 2005 to the 

total remaining emissions. Staff 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 from 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 almost 2322.5% above the projected remaining 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 

30 

Tons 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 Emissions and RTC Holdings 

2 The growth factor for the refineries is 1. Electric generating facilities are expected to be more efficient with growth factor of 0.89 

(2014 California Gas Report). The average growth factor for other non-refinery facilities is 1.1 (Southern California Association 

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. 
Draft Final Staff Report – NOx RECLAIM 5

October 6November December 4, 2015 

Staff is proposing to distribute the 14 tpd NOx RTC reductions to 56 facilities and investors that 

hold 90% of the 26.5 tpd RTCs. Investors are grouped with the refineries and treated as a facility 

for shave purposes. The remaining 219 facilities 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 different 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 electricity 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 reconcile their 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 Basin meet the PM2.5 standard deadlines as well as the 

ozone standards in 2023 and 2031. Staff is proposing the following implementation schedule for 

NOx RTC reductions: 

2016 – 4 tons per day 

4 The ICEs and small boilers or heaters in the remaining 219 facilities could be subject to additional BARCT but the 

potential emission reductions totaled less than 0.1 tpd. 
Draft Final Staff Report – NOx RECLAIM 6

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 NOx RECLAIM program ranged 

from 5 tpd to 8 tpd. Staff is proposing a 4 tpd RTC reduction in 2016. Additional BARCT 

implementation will take about 2 - 4 years for planning, permitting, and construction, 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 in Table EX.3. The total Present Worth Values 

(PWVs) of the project range from $728 M to $1.1 B, and the overall cost effectiveness 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 

(tpd) 

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
Draft Final Staff Report – NOx RECLAIM 7

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 4th quarter 2012. In 2013, staff formed a RECLAIM Working 

Group to discuss potential amendments to the 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. The first meeting was conducted on 

January 31, 2013. A list of participants is shown in Table EX.5. 

To gather pertinent information for rule development, staff sent out Survey Questionnaires to 38 

facilities, including the top 37 emitting facilities in 2011 and a cement facility which was the 

highest NOx stationary emission sources in 2008. Since January 2013, eleven fourteen Working 

Group Meetings were held to discuss potential BARCT 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, SCAQMD staff contracted with two 

consultants (Environmental Technology Services, Inc. (ETS) and Norton Engineering 

Consultants Inc. (NEC)) to conduct independent 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 consultants completed their analyses in December 2014, 

and staff held the 8th Working Group Meeting in January 7, 2015 to report on the consultants’ 

findings to the stakeholders. A CEQA and Socioeconomic scoping session was held in January 

8, 2015 and staff received ten comment letters. From January to March 2015, staff reviewed the 

consultants’ analyses and addressed comments received in response to the CEQA and 

Socioeconomic scoping session. Staff also extended 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 than 85% of the 2011 emissions 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 generate less than 0.1 tpd emission reductions and staff 

did not identify any more stringent BARCT for other equipment at these facilities.
Draft Final Staff Report – NOx RECLAIM 8

October 6November December 4, 2015 

number of air pollution control manufacturers to discuss control technologies, and invited the 

manufacturers to write manuscripts and give presentations at the 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 meetings 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 RECLAIM 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 1st RECLAIM 

Working Group Meeting was conducted 

March 20, 2013 2nd RECLAIM Working Group Meeting 

June 13, 2013 3rd RECLAIM Working Group Meeting. Staff conducted a Survey 

to gather information for rule development. 

September 19, 2013 4th RECLAIM Working Group Meeting 

Calendar Year 2014 

January 22, 2014 5th RECLAIM Working Group Meeting 

March 18, 2014 6th RECLAIM Working Group Meeting 

March 21, 2014 1st Stationary Source Committee Meeting 

July 31, 2014 7th RECLAIM Working Group Meeting 

September 2014 –

December 2014 

Staff contracted ETS and NEC to conduct independent BARCT 

analyses for the non-refinery and refinery 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 8th 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. 
Draft Final Staff Report – NOx RECLAIM 9

October 6November December 4, 2015 

April 10, 2015 The contract for NEC was extended to separate confidential reports 

for the refineries. This task was completed April 10, 2015 

April 29, 2015 9th RECLAIM Working Group Meeting 

June 4, 2015 10th RECLAIM Working Group Meeting 

July 9, 2015 11th RECLAIM Working Group Meeting 

July 22, 2015 Public Workshop. Release Preliminary Draft Staff Report and Rule 

Language 

July 24, 2015 2nd Stationary Source Committee Meeting 

August 1314, 2015 Release Draft Program Environmental Assessment. Draft PEA 

commenting period extended to October 6, 2015 

September 9, 2015 Release Draft Socioeconomic Report 

September 23, 2015 3rd Stationary Source Committee Meeting 

12th RECLAIM Working Group Meeting 

September 29, 2015 Public Consultation Meeting 

October 14, 2015 3rd 4th Stationary Source Committee Meeting 

November 20, 2015 5th Stationary Source Committee Meeting 

November 23, 2015 13th RECLAIM Working Group Meeting 

November 30, 2015 14th RECLAIM Working Group Meeting 

November 6December 

4, 2015 

Public Hearing 
Draft Final Staff Report – NOx RECLAIM 10

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 Independent System Operator (CalISO 
Draft Final Staff Report – NOx RECLAIM 11

October 6November December 4, 2015 

Bay Area Air Quality Management District 

Santa Barbara Air Pollution Control District 

San Joaquin Valley Air Pollution Control District 

U.S. Environmental Protection Agency 
Draft Final Staff Report – NOx RECLAIM 12

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 regulations 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 BARCT 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 emission reductions that 

would have occurred under a command-and-control 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 technology 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 emission limitation that is 

based on the maximum degree of reduction achievable 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 and 24-hour PM2.5. Scientific studies have found 

an associations between exposure to particulate matter and ozone and significant health problems, 

including asthma, chronic bronchitis, reduced lung function, irregular heartbeat, heart attack, and 

premature death in people with heart or lung disease. Individuals particularly sensitive to air 

pollution exposure include older adults, people with heart and lung disease, and children. 
Draft Final Staff Report – NOx RECLAIM 13

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 dioxide, and nitrogen dioxide. 

The effect of reducing emissions of each of these pollutants varies by area depending on the 

composition of the atmosphere, concentrations of these pollutants and other area-specific factors. 

The federal EPA requires the SCAQMD to implement all reasonably available control measures 

(RACM) and reasonably available control technology (RACT) considering economic and 

technical feasibility and other factors to reduce criteria air pollutants. 

On March 12, 2008, the EPA strengthened its ground-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 emission reductions and attainment required in the 

previous calendar year. NOx is a major precursor of ozone and PM2.5, and reducing NOx is 

essential for the Basin to attain the ozone ambient 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 the 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 standard, and will be required to submit a new 

attainment plan. If Phase I was 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 implementation date for Control Measure CMB-01 were estimated to be 2015 and 2020, 

respectively. The analysis done for these amendments 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 effective technologies. The control measure CMB-01 

mentioned that additional reductions would be sought if required to implement BARCT, and that 

all feasible reductions are needed to attain the ozone standards. 
Draft Final Staff Report – NOx RECLAIM 14

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 requirements, as well as monitoring, reporting, and recordkeeping 

requirements. The RECLAIM program started with 392 NOx facilities in 1993, dropped to 281 

facilities in 2011, with 275 facilities by end of the 2013 compliance 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 control 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 implemented 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 specified 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 Holdings NOx (tons) 

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 
15

NOx 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 RTC Price versus Threshold 

700,000 

600,000 

NOx 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 their aggregate RECLAIM NOx emissions remained 

below their NOx allocations for each compliance year since 2005. RECLAIM facilities had a high rate 

of compliance for covering emissions with RTCs. The same was true for all other years of the program 

except for 2000 and 2001 when there was a California power crisis. The 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 the past 5 years were not used, approximately 5.45 

tpd – 8.41 tpd. 
Draft Final Staff Report – NOx RECLAIM 16

October 6November December 4, 2015 

Table 1. 1 – Audited Emissions, RTC Holdings 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 enter 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 treating 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 include the cement kilns in the inventory since 

they were non-operational and subsequently 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 amendments. Refineries hold over half of the 

RTCs with the second most predominant RTC holding industry being electrical electricity 

generating facilities.
Draft Final Staff Report – NOx RECLAIM 17

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) 
Draft Final Staff Report – NOx RECLAIM 18

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 estimated during the development of the 2012 AQMP, 

however staff’s analysis of BARCT shows that additional reductions from RECLAIM NOx 

sources are possible. Staff is proposing that the 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 
Draft Final Staff Report – NOx RECLAIM 19

October 6November December 4, 2015 

Table 2. 2 - Top Ten Ranking of NOx Emissions 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, emitted 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 emissions from the entire NOx RECLAIM universe. The 

cement facility, the highest emitting NOx facility 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 level of 9,677 tons per year (26.5 tpd). 
Draft Final Staff Report – NOx RECLAIM 20

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 
Draft Final Staff Report – NOx RECLAIM 21

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 Monitoring 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 based 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 contributed 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%
Draft Final Staff Report – NOx RECLAIM 22

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 allocations were adjusted to be equal to the 1991 AQMP projected 

inventory for RECLAIM sources in 2003. The 2005 future year allocations were set equal to the 

2003 allocations. In 2005, the SCAQMD staff conducted a BARCT assessment, 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 Rule 2002 for individual equipment categories where 

improved control technologies were 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 reductions, 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 
Draft Final Staff Report – NOx RECLAIM 23

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 Levels 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 BARCT 

analysis for cement kilns and reduced the remaining emissions projected to the 2023 level for the cement facility to the BARCT level. 
Draft Final Staff Report – NOx RECLAIM 24

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 that are expected to have occurred concurrently 

with the energy efficiency projects to reduce 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 Reductions 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
Draft Final Staff Report – NOx RECLAIM 25

October 6November December 4, 2015 

Chapter 4 – Costs and Cost Effectiveness 

This chapter discusses both the preliminary analysis 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 used for costs and cost effectiveness 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 = (PWV2015 BARCT – PWV2000/05 BARCT) /(ER2015 BARCT – ER2000/05 BARCT)/25/365 

Where: 

CE incremental = Incremental Cost Effectiveness, $/ton 

PWV2015 BARCT - PWV2000/05 BARCT = Incremental costs to achieve additional 

control to meet the 2015 BARCT level from the 2000/2005 BARCT level 

ER2015 BARCT - ER2000/05 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. Staff also presented the cost effectiveness estimated with the 
Draft Final Staff Report – NOx RECLAIM 26

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 rule amendment that was adopted by the 

District Governing Board. The results of staff’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 cost effectiveness. The consultants’ 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 Table 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 BARCT level of 5 - 10 ppmv instead of 2 ppmv previously 

recommended by staff. Staff agreed with NEC’s recommendation and changed the 

recommendation to 10 ppmv BARCT for the coke calciner. 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 further discussion. Table 4.3 shows the ranges of PWVs 

and cost effectiveness values for the refinery sector based on the revised proposal. 
Draft Final Staff Report – NOx RECLAIM 27

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 Usin g Incremental 

Category 2014 NEC’s Inform ation 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. 
Draft Final Staff Report – NOx RECLAIM 28

October 6November December 4, 2015 

Table 4. 2 – Initial Proposal - BARCT Levels, Costs and Cost Effectiveness - Non-Refinery 

Sector (December 2014) 

Proposed 2014 Incremental Staff’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 the preliminary proposals. Staff’s revised 

recommendations are presented below. 

Refinery Sector 

Staff’s current recommendations for the refinery sector are tabulated in Table 4.3. Please refer to 

Part I, Appendices A-J for additional information. 
Draft Final Staff Report – NOx RECLAIM 29

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 average 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. 
Draft Final Staff Report – NOx RECLAIM 30

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 for 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 average 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. 
Draft Final Staff Report – NOx RECLAIM 31

October 6November December 4, 2015 

Chapter 5 - RTC Reductions 

Remaining Emissions 

As discussed in the Public Process section, staff started the discussion 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 were 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 emissions for each NOx source category in the 

refinery sector. In 2014, staff estimated the total 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 changed 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 remaining emissions for the SRU/TG incinerators 

increased to 0.11 tpd. 
32 Draft Final Staff Report – NOx RECLAIM 

October 6November December 4, 2015 

Table 5. 1 - Remaining Emissions for Refinery Sector 

Total No 

of Units 

2011 

Emissions 

(tpd) 

2000/2005 

BARCT 

2011 Emissions 

at 2000/2005 

BARCT 

(tpd) 

2015 BARCT 

2011 

Emissions at 

2015 BARCT 

(tpd) 

2023 Emission 

Reductions 

Beyond 

2000/2005 

BARCT 

(tpd) 

2023 Emission at 2015 BARCT 

with GF = 1 

(tpd) 

FCCUs/CO Boilers 8 1.08 85% control 0.60 2 ppmv 0.17 0.43 0.17 Turbines/Duct Burners 21 1.33 62.27 lbs/mmcft 4.86 2 ppmv 0.72 4.14 0.72 Coke Calciner 2 0.55 30 ppmv 0.25 10 ppmv 0.08 0.17 0.08 SRU/TG Incinerators 17 0.43 RV 0.43 2 ppmv (or 95% control) 0.11 0.32 0.11 Boilers/Heaters > 110 mmbtu/hr 73 4.88 5 ppmv 0.82 2 ppmv 0.38 0.44 0.38 Boilers/Heaters >40-110 mmbtu/hr 69 2.00 25 ppmv 0.97 2 ppmv 0.47 0.50 0.47 Boliers/Heaters 20-40 mmbtu/hr 52 0.45 9 ppmv 0.10 n/a 0.10 0.00 0.10 Boilers/Heaters <20 mmbtu/hr 18 0.06 12 ppmv 0.02 n/a 0.02 0.00 0.02 Other Major/Large Sources 5 0.11 n/a 0.10 n/a 0.10 0.00 0.10 Other Process Units n/a 0.60 n/a 0.60 n/a 0.60 0.00 0.60 

Total 265 11.50 8.76 2.76 6.00 2.76 
Draft Final Staff Report – NOx RECLAIM 33

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 the 2023 remaining emissions for the non-refinery 

sector to be 8.77 tpd. In 2015, staff revised the number to 7.47 tpd as a result of the following 

changes: 

x The baseline for electrical electricity generating facilities was changed from 2011 to 2012. The 

2011 and 2012 baseline emissions were 1.45 tpd and 2.50 tpd, respectively. Staff also used 

either the BACT level or the level stated in the permit conditions to estimate 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 remaining emissions for the 

electrical electricity generating facilities. As a result of these changes, the 2023 remaining 

emissions for electrical electricity generating facilities were changed to 2.04 tpd. 

x The remaining emissions from non-electrical electricity generating facilities were changed to 

1.37 tpd; and 

x The remaining emissions from other sources were changed to 4.06 tpd. 
34 Draft Final Staff Report – NOx RECLAIM 

October 6November December 4, 2015 

Table 5. 2 - Remaining Emissions for Non Refinery Sector (May 2015) 
Draft Final Staff Report – NOx RECLAIM 35

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 refinery 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 at the 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 Electricityal Generating 

Facilities 

Staff has received input from several electricityal generating facility operators that have concerns 

with concurrent compliance with the RTC allocation shave and the new source review (NSR) 

holding requirements per Rule 2005. New facilities that entered into 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-RECLAIM power producing facilities only need to 

hold RTCs for one year if their PTEs increase, unless their new PTEs exceed their initial 1993 

allocation. Electricityal producing generating facilities often operate at a capacity factor well 

below the PTE level during any given compliance year. The combustion equipment for these 
Draft Final Staff Report – NOx RECLAIM 36

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 programmatically for all post-1993 electricityal producing generating 

facilities. This account would reduce the individual 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 electricityal generating facilities would be allowed to access this account to offset 

emissions (rather than just satisfy NSR holding requirements) if the Governor 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 electricity 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 electricityal generation generating facilities. Second, it provides 

an emergency source of RTCs to be accessed in the case of a power crisis. Any new electricityal

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 includes a NOx RTC shave of 14 tpd rather than 

the 14.8 tpd calculated above. The 0.8 tpd difference 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 collectively 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 Table 5.5. Staff is proposing not to shave the remaining 219 

facilities that hold only 10% of the 26.5 tpd RTCs because there was limited or no new BARCT 

identified for other types of equipment and operations there. Other approaches to determine the 

RTC reductions as shown in Table 5.4 were analyzed as project alternatives in the CEQA analysis. 

For further information, please refer to Part III, Appendix U of this staff report. 

Staff is proposing the following 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 
Draft Final Staff Report – NOx RECLAIM 37

October 6November December 4, 2015 

As shown in Table 1-1 of Chapter 1, in the past 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 implementation will take about 2 – 4

years for planning, permitting, and construction, and 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 + Refineries/ Electricity 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 
Draft Final Staff Report – NOx RECLAIM 38

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 
Draft Final Staff Report – NOx RECLAIM 39

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 
Draft Final Staff Report – NOx RECLAIM 40

October 6November December 4, 2015 

Chapter 6 – Summary of the Proposed Changes in Rule 

Language and Draft Program Environmental 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 the 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 the NOx limits among its facilities. Monitoring, 

reporting, and recordkeeping requirements of Rule 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 condition 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 has more than one facility subject to RECLAIM 

upon removing all of the facilities from RECLAIM simultaneously, the operator has a single 

opportunity to re-distribute the RTCs holdings among 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 that 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 four possible scenarios that may trigger New Source 

Review (NSR) provisions for NOx. The table below shows the potential conditions that may be 

imposed for each scenario: 
Draft Final Staff Report – NOx RECLAIM 41

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), intercooled, 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 for the refinery and non-refinery sectors are 

summarized in Table 6 of Rule 2002. 

The proposal would result in a programmatic reduction of 14 tons per day RTC holdings over 7 

years. Four tons per day would be reduced in 2016 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. 
Draft Final Staff Report – NOx RECLAIM 42

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) multiplied by the RTC holdings (as of September22,

2015) of all the Major Refineries 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 facilities 

listed in Table 8. Please see Appendix U for 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 subparagraph. 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 generating facilities listed in Table 9 will be used 

to fund a Regional NSR Holding Account that can be used, along with their Non-tradable/Nonusable holdings, by these facilities to help meet their ongoing NSR holding requirements. 

Subparagraph (f)(1)(E) updates the 12-month rolling average 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 AQMP 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 include a commitment and schedule to conduct a more 

rigorous cost-effectiveness, market analysis, and socioeconomic impact assessment of the 

RECLAIM program. 
Draft Final Staff Report – NOx RECLAIM 43

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 Electrical 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 actual 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 derived 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 unlikelihood that a facility could meet the stringent 

requirements listed therein, staff is proposing to remove the subdivision in its entirety. .
Draft Final Staff Report – NOx RECLAIM 44

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-tradable credits. However, a new RECLAIM 

facility will have to continue to hold adequate RTCs equal to the amount of emission increases at 

the beginning of each compliance year. Any unused 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 RTCs at the end of the quarter. To remedy this 

burdensome RTC holding requirement for new electrical 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) above. 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 access during a power crisis as also described in 2002(f)(4)) . Please 

see Appendix X for further explanations. 

Other Administrative Amendments 

Besides the changes described in Rule 2002 and 2005 described 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. 
Draft Final Staff Report – NOx RECLAIM 45

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 increase the 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. In fact, 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 Emission Standards includes a row for Diesel 

Combustion, which includes a BARCT Emission Standard of “15 ppmv as required under Rule 

431.2.” However, the standard in Rule 431.2 is actually “15 ppm by weight” rather than 15 ppmv 

(i.e., 15 ppm by volume). The staff proposal would correct 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 due 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 required for monitoring, reporting, and recordkeeping 

for RECLAIM sources such as the timing and frequency of Semi-Annual Assessments in the form 

of Relative Accuracy Test Audits (RATAs) for CEMS. RATAs must be conducted while the 

equipment 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. 

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 Electrcity 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-operational 
Draft Final Staff Report – NOx RECLAIM 46

October 6November December 4, 2015 

status. The inherent 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 

and criteria, allow RECLAIM Facility Permit Holders of equipment experiencing these 

extenuating circumstances to postpone RATAs. The specific conditions and criteria are further 

explained in details in Appendix X. 

Proposed Amended Rules 2011, Appendix A, Attachment E and 2012, Appendix A, 

Attachment F – Clarification of “Standard Gas Conditions” 

Proposed amendments to Rule 2011, Appendix 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 further 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 analysis in the NOP/IS. These comment letters 

and responses to individual comments are included 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 raised 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 until October 6, 2015. The Draft Socioeconomic 

Analysis was released on September 9, 2015. 
Draft Final Staff Report – NOx RECLAIM 47

October 6November December 4, 2015 

Draft Findings under California Health and Safety Code 

California Health and Safety Code § 40727 requires that prior to adopting, amending or repealing 

a rule or regulation, the AQMD Governing Board shall make findings of necessity, authority, 

clarity, consistency, non-duplication, and reference based on relevant information 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, 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) to seek additional emission reductions from 

RECLAIM relative to the 2012 AQMP (Control Measure CMB-01), to demonstrate BARCT 

equivalence pursuant to California Health and Safety Code §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 Oxides 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 with or contradictory to, 

existing statutes, court decisions or state or federal regulations.

Non-Duplication 

The proposed amended rules will not impose the same requirements 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. 
Draft Final Staff Report – NOx RECLAIM 48

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 equipment subject to a command-and-control 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 on an affected source. The current proposed 

RECLAIM amendment primarily seeks to reduce RTCs in the market and NOx emissions. There 

are no significant changes proposed to the other program elements, such as enforceable procedures, 

operating parameters or work practice requirements. In addition, amendments to the monitoring, 

recordkeeping, and reporting requirements are administrative 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 equipment categories listed in Tables 

1 and 3 of Rule 2002 were examined by staff and presented to stakeholders for comments and 

feedback. However, as shown in Table 3.1 of this staff report, new BARCT 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 calciner, sulfur recovery units/tail 

gas incinerators, cement kilns, container glass melting furnaces, sodium silicate furnace, heat 

treating furnaces greater than 150 mmbtu/hr, non-refinery 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 derive any new control standards. This analysis 

included review of potentially applicable requirements from other air pollution control districts or 

agencies, applicable AQMD rules, as well as emission controls achieved in practice or otherwise 
Draft Final Staff Report – NOx RECLAIM 49

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 reductions are based on the determination of new BARCT for certain 

emission sources. The resulting equipment-level reductions that would have occurred if applied 

with the same percentage under a command-and-control 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 modifications, installation of control equipment, or 

purchasing RTCs. 

Notwithstanding the aforementioned discussion, RECLAIM facilities are subject to the 

requirements of other AQMD regulations 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 – Fugitive Dust. It should be noted that there are 

federally mandated programs, such as New Source Review (BACT/LAER), Prevention of 

Significant Deterioration, and Standards 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, shutdown, 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 does not contain any duplicative or conflicting 

regulatory requirements. 

Incremental Cost-Effectiveness 

Health and Safety Code Section 40920.6 requires an incremental cost-effectiveness analysis for 

Best Available Retrofit Control Technology (BARCT) rules or emission reduction strategies when 

there is more than one control option that would achieve the emission reduction objective of the 

proposed amendments, relative to NOx. The proposed control option is what was analyzed in the 

BARCT analysis, while the alternative control option is BARCT control to a less stringent level. 
Draft Final Staff Report – NOx RECLAIM 50

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 the difference in their emission 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 reductions of the proposed control option are also 

factored into the final calculation. 

The difference of the PWV of the alternative control option and the proposed control option (the 

PWV is the same in this case) is divided by the 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: 

(Ca – Cp) / (Ea – Ep) = $ costs /per ton 

When calculated across all the source categories 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 effectiveness values calculated for all the source 

categories subject to the BARCT analysis. 
Draft Final Staff Report – NOx RECLAIM 51

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. 
Draft Final Staff Report – NOx RECLAIM 52

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 Appendix J that discuss 1) the NOx control 

technologies, 2) costs and cost effectiveness analyses for major NOx sources 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 Survey Questionnaires sent to the refineries in 

2003 2013 to collect pertinent information for this BARCT analyses are included in Appendix L. 
Draft Final Staff Report – NOx RECLAIM 53

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 Wilmington), 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 continuous emission monitoring system (CEMS), and 

reported on a daily basis electronically to the SCAQMD. A brief description of the process is 

presented below. 

An FCCU converts heavy oils into more valuable gasoline and lighter products. A schematic of 

the process is shown in Figure A.1. The process uses a very fine catalyst that behaves as a fluid 

when aerated with a vapor. The fluidized catalyst is circulated 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 regeneration reaction is exothermic. 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 efficiency. While the cracked hydrocarbon vapors are 

routed overhead to a distillation column for separation 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 steam-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 designed and operated to either partially burn 

the coke on the catalyst to a mixture of carbon monoxide (CO) and carbon dioxide (CO2), or 

completely burn the coke to CO2. The regenerator temperature is carefully controlled to prevent 

catalyst deactivation by overheating and to provide the desired amount of carbon burn-off. This 

is done by controlling the air flow to give a desired CO2/CO ratio in the exit flue gases or the 

desired temperature in the regenerator. The flue gas containing a high level of CO is routed to a 

supplemental-fuel fired CO boiler if needed to completely burn off the CO to CO2. 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. 
Draft Final Staff Report – NOx RECLAIM 54

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 FCCU is a major source of sulfur oxides (SOx), 

nitrogen oxides (NOx), particulate matter (PM10, PM2.5), as well as ammonia (NH3), hydrogen 

cyanide (HCN) and other pollutants in the refinery. Approximately 90% of the NOx generated 

from the FCCUs are from the nitrogen in the feed that is accumulated in the coke which is then 

burned-off in the regenerator. This portion of the NOx is called “fuel” NOx. “Fuel” NOx is a 

combination of nitric oxide (NO), nitrogen dioxide (NO2), and nitrous oxide (N2O). 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 “prompt” NOx generated from the reaction between 

nitrogen and oxygen in the combustion air. The NOx emissions from the FCCU are typically 

controlled with selective catalytic reduction (SCR), LoTOx scrubbers, 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 

NH3 

Steam 

NO, HCN, N2 SO2, 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 emissions from the six FCCUs (two with downstream 

CO boilers/heat exchangers) located in the 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 Refinery 4, 7 and 9 have no NOx controls. 

As shown in Table A.1, Refinery 1’s FCCU with SCR currently emits at a level under 2 ppmv 

NOx (with a 5 ppmv ammonia slip.) The NOx concentrations from other FCCU/CO units vary 

from 6 to 45 ppmv. Figure A.2 graphically shows the 2011 NOx emissions and the regenerator 
Draft Final Staff Report – NOx RECLAIM 55

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 FCCU operating 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 regenerator.) 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 ppmv with 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 FCCUs 

2011 Emissions (tons per day) 

NOx Concentration (ppmv) 

Figure A. 3 - 2011 NOx Emissions and Feed Rates for Refinery FCCUs 
Draft Final Staff Report – NOx RECLAIM 57

October 6November December 4, 2015 

Control Technology 

The commercially available control technologies for NOx are discussed below. 

Selective Catalytic Reduction (SCR) 

For the past two decades, SCR technology has been used successfully to control NOx emissions. 

The technology is considered mature and commercially available. SCRs can be designed to reduce 

95%-98% NOx emissions from the FCCUs and achieve 2 ppmv NOx while maintaining a low 

ammonia slip of less than 5 ppmv. 1-17 

SCR is an effective control technology for NOx which uses ammonia (NH3) to selectively reduce 

NOx to nitrogen through the following reactions: 2 - 4 

4 NH3 12ĺ12 + 6 H2O (Reaction 1) 

4 NH3 + 2 NO + 2 NO2 ĺ12 + 6 H2O (Reaction 2) 

It should be noted that, at temperatures above 797 oF, ammonia can be oxidized to form NO and 

N2O. These are undesirable reactions since NO and N2O will ultimately convert to NOx and 

increase the NOx emissions. 5

4 NH3 + 5 O2 ĺ12+ 6 H2O (Reaction 3) 

4 NH3 + 4 NO + 3 O2 ĺ12O + 6 H2O (Reaction 4) 

A successful SCR catalyst can facilitate the reduction of NH3 (Reaction 1 and 2) while subsiding 

the NH3 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 stochiometricstoichiometric amount of ammonia required is 1 mole of NH3 per mole of NOx 

reduced (NH3/NOx = 1). Ammonia injection and mixing are critical since a non-uniform 

distribution and mixing of ammonia can result in inadequate NOx conversion and extensive 

ammonia slip. 

To reduce the ammonia slip caused by imperfect ammonia distribution and mixing, SCR 

manufacturers have developed the Ammonia Slip Catalyst (ASC), a layer of catalyst which can be 
Draft Final Staff Report – NOx RECLAIM 58

October 6November December 4, 2015 

installed downstream of the SCR catalyst. Early generation of ASCs were based on precious metal 

which is highly active for NH3 oxidation. The current newly developed ASCs selectively favor 

the NH3 reduction over the NH3 oxidation: NH3 is partially oxidized to NO (Reaction 3) and NO 

is then quickly reduced to N2 (Reaction 1 and 2). In addition, the advanced ACSs highly support 

the oxidation of CO to CO2. 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 NH3/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, aqueous ammonia has lower risks 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 atomization 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 (SO2) to sulfur trioxide (SO3) conversion and ammonium bisulfate (ABS) formation 

are undesirable reactions in the SCR process. SO3 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 ratio of ammonia to NOx, the SO3 concentrations, and fly ash 

contents; and the methods to control SO3 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 

LoTOxTM Application with Scrubber 

LoTOxTM stands for “Low Temperature Oxidation” process 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 solution, lime or limestone. The LoTOxTM process is a low 

temperature operating system, optimally operating in a range of 140 - 325 degrees F. The 

LoTOxTM is a registered trademark of Linde LLC. (previously BOC Gases) and was later licensed 

to BELCO of Dupont for refinery applications. The LoTOx application is explained below. 19 - 27 
Draft Final Staff Report – NOx RECLAIM 59

October 6November December 4, 2015 

A typical combustion process produces about 95% NO and 5% NO2. Both NO and NO2 are 

relatively insoluble in aqueous solution, and thus a wet gas scrubber is not efficient in removing 

these insoluble compounds from the flue gas stream. However, with the introduction of ozone, 

NO and NO2 can be easily oxidized to highly soluble compounds N2O5 (Reaction 5 and 6) and 

subsequently converted to nitric acid HNO3 (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 SO2 oxidation reaction (Reaction 11), and as a result, there is no ABS or SO3

formation. The LoTOx process can be integrated with any types of wet scrubbers (e.g. venturi, 

packed beds), semi-dry scrubbers, or wet electrostatic precipitators (ESPs). 

NO + O3 ĺ122 + O2 (Reaction 5 - Fast) 

2 NO2 + O3 ĺ12O5 + O2 (Reaction 6 – Fast) 

N2O5 + H22ĺ+123 (Reaction 7) 

HNO31D2+ĺ1D123 + H2O (Reaction 8) 

+12&D&2ĺ&D123)2 + H2O + CO2 (Reaction 9) 

+12&D2+ĺ&D123)2 + 2H2O (Reaction 10) 

SO2 + O3 ĺ623 + O2 (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 liquid 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 individual 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/O3 of about 1.75 – 2.5 is needed to 

achieve 90% to 95% NOx conversion and reduction. Since sulfites are ozone scavengers, the 

LoTOx process typically has a very low ozone slip of 0-3 ppmv. 

Several advantages of LoTOx application in comparison to SCR are: 

 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 

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, SO3, and ABS issues associated with LoTOx application. 
Draft Final Staff Report – NOx RECLAIM 60

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 used for lead smelting, operated by Quemetco 

Inc., City of Industry in California. The demonstration 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 

EDVTM scrubbers engineered by BELCO since 2007.26 EDVTM is a registered trademark of 

BELCO. LoTOx with EDVTM scrubber is shown in Figure A.4. 

Table A.2 contains a list of the LoTOx applications 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 achieve 2 ppmv NOx from current inlet concentrations 

(85%-95% control efficiency) for FCCUs. 

Figure A. 4 - EDV Scrubber with LoTOx Application 
Draft Final Staff Report – NOx RECLAIM 61

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 generates a dozen of various pollutants (NO, N2O, NO2,

HCN, NH3, CO, SO2 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 first converted to HCN. HCN is thermodynamically 

unstable and it is converted to NH3, N2, NO, N2O, NO2 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 NH3 to N2 and reduce NOx 

emissions. The removal efficiency for NOx Reduction Additives is reported to vary from 50% to 

80%. 28-38 
Draft Final Staff Report – NOx RECLAIM 62

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 N2, 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 technologies 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 FCC fresh catalyst addition rate. The NOx control 

effectiveness of the NOx Reducing Additives would be very specific for each FCCU application. 
Draft Final Staff Report – NOx RECLAIM 63

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 Additive Reduces NOx Emissions by 60% NOx, ppm 
Draft Final Staff Report – NOx RECLAIM 64

October 6November December 4, 2015 

Costs and Cost Effectiveness for SCRs 

Several methodologies were used to estimate the costs and ensuing 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 factor and a consultant’s independent assessment. 

Refinery 1 

The refinery 1 SCR achieved 2 ppmv NOx and 5 ppmv 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 Refinery 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 estimated 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) retrofit their existing SCRs, or 2) add additional 

catalysts to their existing SCRs if space is available (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 
Draft Final Staff Report – NOx RECLAIM 65

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 FCCUs have no controls for NOx emissions. Several manufacturers 

provided costs information for the 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 ABS related problems; and 

estimated that this would add 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 installed costs. Staff used this 20% factor to estimate the 25-year 

operating costs for the new SCRs at all the refineries. Staff added a contingency factor of 1.5 to 

cover additional uncertainties 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 
Draft Final Staff Report – NOx RECLAIM 66

October 6November December 4, 2015 

The cost effectiveness in Table A.3 is estimated using Discounted Cash Flow (DCF) method. The 

cost effectiveness calculated based on the Levelized 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 for SCRs and Staff’s Revised Estimates for SCRs 

In 2014, staff contracted Norton Engineering Consultants (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. 
Draft Final Staff Report – NOx RECLAIM 67

October 6November December 4, 2015 

NEC recommended SCRs with 3 layers of catalysts 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 installed cost to the cost of material and labor.6 NEC further 

added the cost of waste heat boiler modifications, new CEMS and 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 only 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 then followed 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 in the EPA OAQPS Guidelines (Equation 3) were not 

sufficient to cover retrofitting applications at the refineries. The refineries also indicated the 

factors relating equipment costs to TIC should be at least 4, or higher. To reconcile this difference, 

staff presents the PWVs as a range of costs 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 their 

own experience. 
Draft Final Staff Report – NOx RECLAIM 68

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 effectiveness 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 effectiveness 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 threshold 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-

Layer 

With 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 additives were estimated to be about $6,460 per ton 
Draft Final Staff Report – NOx RECLAIM 69

October 6November December 4, 2015 

of NOx reduced using DCF method ($10,660 per ton using LCF method.) The inputs and results 

were summarized in Table A.6.38 

Table A. 6 - Costs and Cost Effectiveness 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 currently have no control. Refinery 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 installed 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 foundation. Staff added a contingency factor of 2 to 

markup the costs provided by the manufacturer to account for any additional modifications needed 

at the site and any variations in annual operating 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 Costs provided by vendor, $ 

AC Ref 4, 7 and 9 = Annual Operating Costs provided by vendor, $ 
Draft Final Staff Report – NOx RECLAIM 70

October 6November December 4, 2015 

Contingency Factor = 2 

Refineries 5 and 6 currently employ SCRs to reduce 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 further 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 application was put in service in 1997. At that time, required 

a large foot print (e.g. 1st generation LoTOx application at a Texas refinery required a foot print of 

30 ft x 80 ft.) The newer generation LoTOx application has a much smaller footprint (e.g. an 

equivalent unit to the Texas refinery application now requires only 25 ft x 30 ft). 

Table A. 7 - Costs and Cost Effectiveness 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 treatment for Refineries 4, 7 and 9. Staff also 

estimated the overall cost effectiveness for the LoTOx/scrubbing multi-component air pollution 

control as shown in Table A.8. 
Draft Final Staff Report – NOx RECLAIM 71

October 6November December 4, 2015 

Table A. 8 – Revised Costs and Cost Effectiveness for LoTOx Scrubbers (March 2015) 

Fac NOx Emission SOx Emission PWV for PWV for Total CE

ID Reductions Reductions LoTOx Scrubbers 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 1.25 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 refineries 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 use LoTOx and scrubbers (Table A-8) for multicomponent control. The total PWVs would be $375 million. 
Draft Final Staff Report – NOx RECLAIM 72

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-years life of the control device is listed in Table A.10. CE is 

estimated as follows: 

CE incremental = (PWV2 ppmv – PWV85% control) / ((ER2 ppmv – ER85% 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 achieved 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 Reductions = 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 – SCR 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 
Draft Final Staff Report – NOx RECLAIM 73

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 LoTOx 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 LoTOx 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 Refineries 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 
Draft Final Staff Report – NOx RECLAIM 74

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, Paul Anderson, Johnson Matthey. Paper #33233. 

A&WMA’s 107th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 

6. UltraCat Catalytic Filters Remove PM, SO2, 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 SCR. Haldor Topsoe. Presentation at the 2nd 

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 website 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. Hastings of Cormetech, Inc. and A. Hattori of 

Mitsubishi Power Systems, Inc. Presentation 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 Poster 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, and Anhydrous Ammonia Operating Costs. of

Canyon Energy Project. D. Kirk of Fuel Tech Inc. to C. McFarlin of California Energy 

Commission, September 3, 2008. 
Draft Final Staff Report – NOx RECLAIM 75

October 6November December 4, 2015 

14. Influence Factors and Control Research on Ammonium Bisulfate Formation in the Process of 

Selective Catalytic Reduction. 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 Institute, Taiwan. Paper #32657. 

A&WMA’s 107th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 

19. LoTOxTM – Novel NOx Control Solution. Naresh J Suchak, Ph.D., Monica Caldwell, Peter 

Studer, Frank R Fitch, Ph.D., Linde Gases. Paper #33612. A&WMA’s 107th Annual 

Conference & Exhibition, June 24-27, 2014, Long Beach California. 

20. Meeting Tighter NOx Emission Rules – A Low Temperature Oxidation Technology Uses 

Ozone to Remove Very Low Levels of Nitrogen Oxide from Refinery Gases. S. Harrison, N. 

Suchak, F. Fitch, Linde Gases. www.digitalrefining.com/article/1000954. PTQ Q3 2014 

21. Wet Scrubbing-based NOx Control Using LoTOx Technology – First Commercial FCC StartUp Experience. Nicholas Confuorto of BELCO Technologies, Jeffrey Sexton of Marathon 

Petroleum Company LLC. www.digital refining.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. 
Draft Final Staff Report – NOx RECLAIM 76

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 Emission Control in FCC Units. Todd Hochheiser, 

Bart de Graaf, Paul Anderson. Johnson Matthey. Paper #33231. A&WMA’s 107th 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, Charles 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 Technology 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 RECLAIM, 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. 
Draft Final Staff Report – NOx RECLAIM 77

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 cracking, 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 refineries classified as major or large NOx sources. 

The refinery heaters and boilers primarily burn refinery 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 contribution 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 

Asphalts 

Jet, Diesel 

Gasoline 

Jet, Diesel 

Gasoline 

Refinery Gas 

LPG 

Figure B. 1 - Refinery Processes 
Draft Final Staff Report – NOx RECLAIM 78

October 6November December 4, 2015 

Emission Inventory 

There are a total of 212 boilers and heaters classified as major and large NOx sources at the 

refineries. The distribution of boilers and heaters and their emissions are shown in Table 5.1. 

Collectively, the 212 boilers and heaters emitted 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 levels 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 between 40-100 mmBtu/hr at 25 ppmv. In 2005, it was estimated that 

51 boilers/heaters would require SCRs to be installed to reduce NOx emissions. Only 4 pieces of 

equipment were retrofitted with SCRs; these were in response to either an EPA consent decree or 

an order of abatement. If all of the boilers and heaters had complied with the 2005 BARCT 

emissions from boilers and heaters would be reduced from 7.39 tons per day to 1.92 tons per day, 

approximately 74% reduction 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 fuel gas in the SCAQMD ranging from 22 to 653 

mmBtu/hr equipped with SCRs have achieved 1.6 - 3.5 ppmv NOx at 3% O2;

x Two boilers, 400 HP and 1000 HP, using natural gas, equipped with LoTOx scrubbers have 

achieved 2 - 5 ppmv NOx at 3% O2;

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% O2 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% O2.

Control Technology 

Commercially available control technologies are SCRs, Great Southern Flameless Heaters, and 

LoTOx applications with scrubbers. Other potential technologies on the horizon are ClearSign, 
Draft Final Staff Report – NOx RECLAIM 79

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 control technologies such as Low NOx burners, 

Ultra Low NOx burners, or Selective Non Catalytic Reduction (SNCR) are not discussed here. 

Selective Catalytic Reduction 

SCR is an effective control technology for NOx which uses ammonia (NH3) 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 with pilots in operation, and 3 ppmv NOx without 

pilots for flameless technology. Great Southern Flameless confirmed the following: 18-21 

x Flameless heaters can be designed to achieve: 

 5 ppmv NOx at 3% O2; or 

 2 ppmv NOx at 3% O2 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% O2; or 

 1 ppmv with pilots off during flameless firing 

Great Southern Flameless can supply 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 modules 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. The flameless heater designed by Great Southern 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 fuel nozzles, 4 air nozzles and 1 nozzle for pilot 

fuel. 
Draft Final Staff Report – NOx RECLAIM 80

October 6November December 4, 2015 

x To pin the flue gas in circulation against the 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 the heater until it eventually rotates out to the 

center of the heater, and up through the uptake ducts and into the convection 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 pending 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 temperatures of the combustion air. 

x The heater has a balanced draft air-preheat system which generates high temperature 

combustion air. High temperature combustion air 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 conventional nozzles disappears and NOx emissions 

decreases significantly in the flameless mode operation. 

Table B.1 below tabulates the temperature profile inside 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 the 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 CO2 emissions. Figure B.2 shows a flameless heater 

modified for oxygen combustion. Table B.2 lists the predicted performance of an oxy-flameless 
Draft Final Staff Report – NOx RECLAIM 81

October 6November December 4, 2015 

heater. Flameless and oxy-flameless heaters come in modules 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) 
Draft Final Staff Report – NOx RECLAIM 82

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 recirculation (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 comprises 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 Control District and efforts 

of scaling up the technology to heaters 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, ClearSign believes that their burners will provide 

substantial economic benefits from more uniform heat distribution, improved process throughput, 

and potentially reduced maintenance costs. 22-23 
Draft Final Staff Report – NOx RECLAIM 83

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 concentration measured at the stack, the heater maximum 

rating, and the year of SCR installation, the equipment costs (in the year of installation), installation 

costs (in the year of installation), and annual operating costs 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 catalyst replacement costs were 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 
Draft Final Staff Report – NOx RECLAIM 84

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 staff 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 individual heaters using the heater maximum ratings. 

The PWVs for 18 heaters are summarized in Table B.4. 14 
85 Draft Final Staff Report – NOx RECLAIM 

October 6November December 4, 2015 

Table B. 4 – Performance and Cost Information of SCRs for Process Heaters from Refinery Survey 

Process mmBtu/hr 2011

Emissions (Tons) 

Year of Installation 

Existing NOx ppmv (3% O2) 

Shared Control 

Equipment Cost ($M) 

Installation 

Cost ($M) 

Marshall 

Index 

PWV ($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 28.11

Note: 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 Figure B.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 $44 million for 653 mmBtu/hr heater.) 
Draft Final Staff Report – NOx RECLAIM 86

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 used a 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 submitted to the SCAQMD in previous CEMS applications. 

Great Southern Flameless 

Great Southern Flameless provided costs data based on the following 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 heater 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 standard 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%)
Draft Final Staff Report – NOx RECLAIM 87

October 6November December 4, 2015 

Table B. 5 - Costs of SCRs Estimated Based 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 (NH3 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
Draft Final Staff Report – NOx RECLAIM 88

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 their estimates did not yet include the economic 

benefits for more uniform heat distribution or improved process throughput and potential reduced 

maintenance costs. ClearSign indicated that their cost estimates were conservative and can be 

adjusted due to market demand. In addition, ClearSign provided an analysis showing the revenue 

savings of about $36,000 per ton NOx reduced using 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 firing rate were developed: 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 representative 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 
Draft Final Staff Report – NOx RECLAIM 89

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 inventory) 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 Devices for Refinery Boilers/Heaters (March 2015) 
Draft Final Staff Report – NOx RECLAIM 90

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 used 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 per ton were excluded from estimating the total 

emission reductions and the average cost effectiveness for the category of boilers and heaters. 

Staff estimated there would be 103 units that would 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% O2 and 5 ppmv ammonia slip is an achievable 

BARCT level. If the refinery heaters and boilers were only burning natural gas, this 2 

ppmv NOx level could be achieved by installing three SCR catalyst 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 (ASC) 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 NOx 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 cost 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 induced draft fan, CEMS and an ammonia injection 

system to their prototype SCR. The resulting profile was sized for a series of heating rates to 
Draft Final Staff Report – NOx RECLAIM 91

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 effectiveness 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 half of the NEC estimate (e.g., for 125 mmBtu/hr, 

staff: $11 million and NEC: $18 million). For heating values approximately 300 mmBtu/hr and 

higher the costs estimate converge (e.g., for 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 that the two approaches were similar in relating firing rate to PWV 

to estimate cost effective SCR applications. However 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 revised the calculated PWVs based on the 

manufacturers’ information. Revised PWVs are included in Figure B.3 above. 
Draft Final Staff Report – NOx RECLAIM 92

October 6November December 4, 2015 

2. For heaters <110 mmBtu/hr with existing SCRs, the 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 estimate are summarized in Table B.10. Table B.11 

provides the details of the application 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 methodologies. The proposed adjustment is 

significantly larger than 0.33 TPD. 

Table B. 10 – Revised Cost Estimates 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 beyond 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) 
Draft Final Staff Report – NOx RECLAIM 93

October 6November December 4, 2015 

Table B. 11 – Details of Cost Estimates 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 
Draft Final Staff Report – NOx RECLAIM 94

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 
Draft Final Staff Report – NOx RECLAIM 95

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 
Draft Final Staff Report – NOx RECLAIM 96

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, Paul Anderson, Johnson Matthey. Paper #33233. 

A&WMA’s 107th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 

4. UltraCat Catalytic Filters Remove PM, SO2, 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 SCR. Haldor Topsoe. Presentation at the 2nd 

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 website 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. Hastings of Cormetech, Inc. and A. Hattori of 

Mitsubishi Power Systems, Inc. Presentation 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 Poster 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 Ammonium Bisulfate Formation in the Process of 

Selective Catalytic Reduction. S. Ma et.al., North China Electric Power University. Journal 

of the Air & Waste Manuscript Paper UAWM-2013. 
Draft Final Staff Report – NOx RECLAIM 97

October 6November December 4, 2015 

13. SCR Costs Data Provided to SCAQMD staff – Refinery Survey. June 2013 

14. SCR Costs Information from a Refinery 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 107th Annual Conference & Exhibition, June 24-27, 2014, Long Beach 

California. 

19. Oxy-Flameless Combustion for Refinery Process Heaters. William C. Gibson, Marianne 

Zimola. Paper #32899. A&WMA’s 107th 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 107th 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 RECLAIM, Non-Confidential Report, Norton 

Engineering Consultants, November 26, 2014. (See Addendum 1) 
Draft Final Staff Report – NOx RECLAIM 98

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 continuous 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 refineries 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 turbine, duct burner, HRSG, and control system. 

Figure C. 1 - Gas Turbine with Duct Burner (victoryenergy.com) 
Draft Final Staff Report – NOx RECLAIM 99

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 turbines/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 mass 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 these gas turbines/duct burners were operated at 

the BACT levels or at the levels specified in the permit conditions at the time the permits were 

issued, the emissions would be 5.99 tons per day, higher than 4.86 tons per day of the 2000 

BARCT. All of the gas turbines are currently emitting at a level below their allocations and below 

the levels at the time their permits were issued. Technology improvements 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 turbine/duct burner with Cormetech SCR and ASC 

operating under a permit condition of 2.5 ppmv NOx, 15% O2 has actually achieved the levels 

1, 6, 9, 25 below 2 ppmv NOx at 15% O2. 

x In 2010, Refinery 5 received a permit to construct 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% O2 and 5 ppmv 

NH3 slip. This unit has been in operation since 2012. 28-29 

x In 2011, Refinery 1 received a permit to construct 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
Draft Final Staff Report – NOx RECLAIM 100 

October 6November December 4, 2015 

The above 7 MW aero-derivative, 46 MW and 85 MW frame gas turbines/duct burners 

demonstrate the feasibility of the proposed level 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 average), which is more stringent than the proposed 

BARCT at 2 ppmv, annual average. 

Table C. 1 - 2011 Emissions for Refinery Gas Turbines/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
Draft Final Staff Report – NOx RECLAIM 101 

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 premixed combustion – 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 the combustion zone and suppresses “thermal” NOx 

formation. The premixing chamber for the combustion 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 deteriorated and must be replaced. Table C.2 

shows potential performance of DLN/DLE in certain 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 emissions from the duct burners remain a challenge for 

DLN/DLE combustor technology. Most manufacturers 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) 
Draft Final Staff Report – NOx RECLAIM 102 

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 combustion. The difference in the CLN and the traditional steam injection 

technology is that CLN can deliver a uniform homogenous mix of steam and fuel to the combustion 

chamber. A schematic diagram for the 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 lowered 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 Power 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. In 2009, 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. Table C.3 below shows a list of CLN installations in 

the past decade. 

Figure C. 2 - Cheng Low NOx (Reference 22) 
Draft Final Staff Report – NOx RECLAIM 103 

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. 
Draft Final Staff Report – NOx RECLAIM 104 

October 6November December 4, 2015 

Figure C. 4 - Effect of Homogeneity and Steam to Fuel Ratio on NOx Emissions in CLN 

Application 

In summary, CLN with a steam to fuel ratio of 1.75 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 software 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 technology for NOx which uses ammonia (NH3) 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 be achieved while maintaining low ammonia slips 

of less than 5 ppmv. 

Cormetech indicated that they have achieved less than 2 ppmv NOx and 2 ppmv NH3 in 10 gas 

turbines. In addition one of the full scale demonstration 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 
Draft Final Staff Report – NOx RECLAIM 105 

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 about 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 catalysts have dropped significantly over time – catalyst 

innovations have been the principle driver, resulting in a 20 percent reduction in catalyst volume 

and costs with no change in performance. 10 Staff developed a cost curve 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 manufacturers and Cheng Low NOx 

Staff then used the PWVs from the cost curve to estimate 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. The total installed costs for SCR and CO provided 

in their application for permit was estimated to be $5.9 million. Staff 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 survey conducted in 2013 that the annual operating 

costs were $375,000 per year, and catalyst replacement costs were $950,000 every 10 years. 8

Using Equation 1 below with a Marshall Index adjustment 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. 
Draft Final Staff Report – NOx RECLAIM 106 

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 that is 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. Manufacturer B believed that with the current SCR 

system at Refinery 1, the refinery could meet 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 information for 1) conventional SCRs and for 2) an 

advanced SCR with ASC for 83 MW and 7 MW cogeneration units with inlet NOx concentrations 

at 35 ppmv and 50 ppmv to get to 2 ppmv and 5 ppmv outlet NOx concentrations. The costs are 

summarized in Table C.4 below: 4
Draft Final Staff Report – NOx RECLAIM 107 

October 6November December 4, 2015 

Table C. 4 – Costs of SCR and ASC for 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 replacement 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 vaporizer 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 multiplier 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 concentrations to 9 ppmv NOx outlet concentration. The gas turbines in the 

SCAQMD currently have inlet NOx concentrations in the range of 6 to 2.5 ppmv. An incremental 

reduction of 80% - 90% is needed to reach 2 ppmv 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. 
Draft Final Staff Report – NOx RECLAIM 108 

October 6November December 4, 2015 

Reference 3 contains the total installed costs and annual operating 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 for 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 information 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. 
Draft Final Staff Report – NOx RECLAIM 109 

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 
Draft Final Staff Report – NOx RECLAIM 110 

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 estimated 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 replacement every 10 years) was used to convert 

the cost effectiveness estimated using DCF method to 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% O2. Refinery 

5 recently changed the catalysts used in Turbine 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 new Turbine D at Refinery 5 uses only 300 cubic 

feet of Cormetech catalysts to reach 2 ppmv NOx. 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 
Draft Final Staff Report – NOx RECLAIM 111 

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 increase NOx reduction effectiveness without 

compromising the ammonia slip. 11, 20, 25, 26 

x Refinery 10’s gas turbine/duct burner is already 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, because 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/duct burner using SCR and ASC. Two 46MW and 83 

MW frame cogeneration units with SCR and CO catalysts were given 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 
Draft Final Staff Report – NOx RECLAIM 112 

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 BARCT 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 be used 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 catalysts. An 83 MW cogeneration with SCR and 

CO catalysts was given a permit to construct since 2012 with a permit condition of 2 ppmv NOx. 

In summary: 

x Incremental Emission Reductions beyond 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) 
Draft Final Staff Report – NOx RECLAIM 113 

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 for Stationary Gas Turbines. Contract No. DEFC02-97CHIO877. ONSITE SYCOM Energy Corporation. 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 Climate Protection Partnership Division, Washington, 

DC. December 2008. 

11. Reducing NOx and NH3 Emissions with Advanced SCR Technology. Rita Aiello, Kevin 

Doura, Mike Baran, Wilson Chu, Paul Anderson, Johnson Matthey. Paper #33233. 

A&WMA’s 107th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 

12. Catalytic Multi-Pollutant Abatement 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. Lindenhoff. SCR DeNOx Catalyst & Technology 
Draft Final Staff Report – NOx RECLAIM 114 

October 6November December 4, 2015 

Department. Haldor-Topsoe. Downloaded 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 Combined Cycle. Technical Update, December 2010. 

20. CLN with SCR as an Emission Control System in CHP Plants Should Meet 2 ppmv NOx. Dr. 

Dah Yu Cheng, Ian Church, Ching-An Cheng. Paper #33051. A&WMA’s 107th Annual 

Conference & Exhibition, June 24-27, 2014, Long Beach California. 

21. Costs information provided by Cheng Combustion. 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. Cheng to Minh Pham on January 10 and February 

5, 2014. 

24. Combating NOx from Refinery Sources Using SCR. Haldor Topsoe. Presentation at the 2nd 

Annual World Refining Technology Summit & Exhibition, 2010, Abu Dhabi. 

www.topsoe.com, posted online and downloaded in January 2014. 

25. SCR and Zero-SlipTM Technology. T.W. Hastings of Cormetech, Inc. and A. Hattori of 

Mitsubishi Power Systems, Inc. Presentation of June 17, 2003 Turbo Expo – Atlanta, GA. 

95% SCR efficiency. Ten units less than 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. 
Draft Final Staff Report – NOx RECLAIM 115 

October 6November December 4, 2015 

27. BASF NOxCat VNX & ZNX for Power Generation 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 Refinery 7 Cogeneration unit. E-mail from 

Cynthia Carter to Minh Pham, February 27 and 28, 2014. 

32. BASF NOx CAT VNX Catalyst and Zeolite. BASF Publication 

33. BARCT Analysis for SCAQMD NOx RECLAIM, Non-Confidential Report, Norton 

Engineering Consultants, November 26, 2014 
Draft Final Staff Report – NOx RECLAIM 116 

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 hot 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 discharging 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 calcining process is shown in Figure D.1. 

The coke calciner produces approximately 400,000 tons per year of calcined products. This plant 

is a global supplier of calcined coke 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% O2 (ppmv) 

2 C67 Afterburner 390,625 65

2 D20 Rotary Kiln 11,400 65

Total (tpd) 0.55
Draft Final Staff Report – NOx RECLAIM 117 

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 commercially available multi-pollutant control technologies for low

temperature removal of NOx. 

LoTOxTM Application 

LoTOxTM stands for “Low Temperature Oxidation” process where ozone is used to oxidize 

insoluble NOx compounds to soluble NOx compounds. 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 combustion 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 1997, and more than two dozen applications with 

EDVTM 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. 
Draft Final Staff Report – NOx RECLAIM 118 

October 6November December 4, 2015 

The 2010 SOx RECLAIM amendments set a BARCT level 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 integrated in any of these scrubbers to reduce NOx, 

SOx, PM and other toxic pollutants. The footprint needed for scrubbers and associated equipment 

was estimated to be about 30 ft x 40 ft. The facility has not yet installed any scrubber since the 

adoption of the SOx RECLAIM amendments in 2010. 

UltraCatTM Application 

UltraCat is also a multi-component air pollution control technology developed by Tri-Mer. 

UltraCat catalyst filters are composed of fibrous ceramic materials embedded with proprietary 

catalysts that can remove NOx, SO2, 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 removal efficiency is about 95%. Dry sorbent such 

as hydrated lime, sodium bicarbonate or trona injected upstream of the catalytic filters is used to 

remove SO2, HCl, and other acid gases with a removal efficiency of 90% - 98%. Particulate control 

to a level of 0.001 grains/dcsf and mercury control are also possible. UltraCat filters are arranged 

in a baghouse configuration with low pressure drop, about 5” water column, 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] 
Draft Final Staff Report – NOx RECLAIM 119 

October 6November December 4, 2015 

Costs and Cost Effectiveness 

LoTOxTM Application 

Table D.2 contains costs information provided by LoTOx manufacturer.4 Staff estimated the 

PWV using the equations below for the Discounted Cash Flow (DCF) method assuming 4% 

interest rate and 25-years life for the control device. Staff applied a contingency factor of 1.5 to 

account for any additional costs that might occur. Incremental cost effectiveness 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 application were estimated to be $22 million and 

$10,347 per ton NOx reduced per DCF method as shown in Table D.3. The CE would be $17,073 

per ton NOx reduced per Levelized Cash Flow (LCF) method. 

UltraCatTM 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 account for any additional costs that might occur. 

The PWV assuming 4% interest rate and 25-years 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. 
Draft Final Staff Report – NOx RECLAIM 120 

October 6November December 4, 2015 

Table D. 2 – Costs of LoTOx and UltraCat 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
Draft Final Staff Report – NOx RECLAIM 121 

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 also suggested that a factor of 1.86 to estimate 

TIC and an adjustment of 1.5 were not conservative enough since space was extremely challenging 

at the coke calciner facility. A factor of 4.5 – 4.6 was more reasonable. 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 commercially available to achieve 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 emission 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) 
Draft Final Staff Report – NOx RECLAIM 122 

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. LoTOxTM – Novel NOx Control Solution. Naresh J Suchak, Ph.D., Monica Caldwell, Peter 

Studer, Frank R Fitch, Ph.D., Linde Gases. Paper #33612. A&WMA’s 107th Annual 

Conference & Exhibition, June 24-27, 2014, Long Beach California. 

3. LoTOx NOx Reduction Technology Installation 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 Minh Pham. November 8, 2013 and May 21, 2014. 

7. BARCT Analysis for SCAQMD NOx RECLAIM, Non-Confidential Report, Norton 

Engineering Consultants, November 26, 2014 
Draft Final Staff Report – NOx RECLAIM 123 

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 recover 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 H2S in the tail gas is oxidized to SO2 before 

emitting to the atmosphere. The refinery SRU/TGTUs 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 have been established for the SRU/TGTUs and incinerators. The 

2010rule amendment included a new BARCT level for 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 evaluation of the performance is ongoing. 

Emission Inventory 

The 2011 NOx emissions from the SRU/TGTUs and 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. 
Draft Final Staff Report – NOx RECLAIM 124 

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 NOx emissions are Selective Catalytic Reduction 

(SCR) and LoTOx. KnowNOx has been installed at two 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 been used successfully to control NOx emissions. 

The technology is considered mature and commercially 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 
Draft Final Staff Report – NOx RECLAIM 125 

October 6November December 4, 2015 

LoTOxTM Application 

LoTOxTM 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 engineered by 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 scrubbers are used in numerous other 

industrial applications such as sulfuric acid plants, coke calciner, metallurgical plants, secondary 

aluminum or copper smelters, coal fired heaters and boilers, sulfur pits, platinum recovery plants, 

cement kilns, meat rendering plants, and medical waste incinerators. DynaWave scrubbers have 

been used in the industries since 1987. 

A BARCT level for SOx was established at 5 ppmv, 0% O2, annual average in 2010. In 2011, 

Refinery 5 installed a new SRU/TGTU with a DynaWave 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% O2. Thus, concurrent reductions of NOx and SOx are feasible and 

cost-effective using a DynaWave and LoTOx combination application. 
Draft Final Staff Report – NOx RECLAIM 126 

October 6November December 4, 2015 

Figure E. 1 - DynaWave Scrubber (Reference 23) 

Figure E. 2 - Ozone Generation Process (Reference 23) 
Draft Final Staff Report – NOx RECLAIM 127 

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, SO2 and Particulate 

Calumet 2010 15,545 40 LTPD SRU Tail Gas Clean Up 

Louisiana SO2 removal with NaOH 

Chevron 2013 27,800 SRU SCOT Tail Gas Clean Up 

California SO2 removal with NaOH 

Sinclair 2009 59,603 FCC Off Gas 

Oklahoma Quench, SO2 and Particulate 

Wyoming Refining 2011 57,746 FCC Off Gas 

Wyoming Quench, SO2 and Particulate 

Pasadena Refining 2008 2,200 S Zorb Off Gas 

Texas SO2 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 SO2 removal with NaOH 

Marathon Ashland 2008 10,100 33 LTPD SRU Tail Gas Clean Up 

Texas SO2 removal with NaOH 

Sinclair 2005 12,830 47.5 LTPD SRU Tail Gas Clean Up 

Wyoming SO2 removal with NaOH 

Sinclair 2005 5,700 18 LTPD SRU Tail Gas Clean Up 

Wyoming SO2 removal with NaOH 

ConocoPhillips 2005 2,000 S Zorb Off Gas 

Louisiana SO2 removal with NaOH 

Navajo 2003 100,000 FCC off gas NaOH scrubber for SO2 and PM 

New Mexico 

ConocoPhillips 2003 3,300 S Zorb Offgas 

Washington SO2 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 
Draft Final Staff Report – NOx RECLAIM 128 

October 6November December 4, 2015 

KnowNOxTM Application 

In lieu of using ozone to convert NO and NO2 to N2O5 and HNO3, the KnowNOx technology uses 

chlorine dioxide ClO2. 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 conversion. The reactions require a smaller vessel in 

relative to the LoTOx reaction chamber. In addition, the KnowNOx process can simultaneously 

reduce NOx, SO2, PM and other contaminants.26-28 

5 NO + 2 ClO2 + H22ĺ1O2 + 2 HCl (Reaction 12 - Gas Phase) 

5 NO2 + ClO2 + 3 H22 ĺ+123 + 2 HCl (Reaction 13 – Gas Phase) 

5 SO2 + 2 ClO2 + 6 H22ĺ+2SO4 + 2 HCl (Reaction 10) 

The conceptual layout for the KnowNOx process is shown in Figure E.3. It includes a three-stages

scrubbing system: SO2 is scrubbed at the 1st stage with a DynaWave scrubber, ClO2 injected to 

the 2nd stage converts NO and NO2 to HNO3 and other soluble salts, and H2S generated in the 2nd 

stage is converted to soluble salts in the 3rd stage. The KnowNOx technology has been installed 

at two locations in the U.S., however, it has not yet been tested in any refinery applications, and 

may not yet have been proven at full scale operations. 

Figure E. 3 – KnowNOx Process (Reference 28) 
Draft Final Staff Report – NOx RECLAIM 129 

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 obtain 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 uncertainties. CE was estimated 

as shown in Equation 2 using the DCF method. For 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. 
Draft Final Staff Report – NOx RECLAIM 130 

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 
Draft Final Staff Report – NOx RECLAIM 131 

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 Scenario 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 Scenarios 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 NH3 costs and $40,000 miscellaneous for a 95% control 

o Dimension of 2000-gallons NH3 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 LoTOxTM 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 LoTOx in one system to reduce both NOx and SOx 

emissions as shown in Table E.5. 24 
Draft Final Staff Report – NOx RECLAIM 132 

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 KnowNOxTM 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 per ton NOx reduced (DCF) and $25 K per ton NOx 

reduced (LCF) as shown in Table E.7. 

Consultant’s Analysis for SCRs and Staff’s Revised Estimates for SCRs and LoTOx 

NEC confirmed that the 2 ppmv proposed BARCT level is feasible for the refinery SRU/TG 

incinerators. However, the consultants indicated 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 
Draft Final Staff Report – NOx RECLAIM 133 

October 6November December 4, 2015 

with 3 layers of catalysts and added the costs 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 factor 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 emission 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**

38,490

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

*this unit was cost effective using SCR technology 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. 
Draft Final Staff Report – NOx RECLAIM 134 

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 technologies 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. 
Draft Final Staff Report – NOx RECLAIM 135 

October 6November December 4, 2015 

References for SRU/TG Incinerators 

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, Paul Anderson, Johnson Matthey. Paper #33233. 

A&WMA’s 107th Annual Conference & Exhibition, June 24-27, 2014, Long Beach California. 

4. UltraCat Catalytic Filters Remove PM, SO2, 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 SCR. Haldor Topsoe. Presentation at the 2nd 

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 website 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. Hastings of Cormetech, Inc. and A. Hattori of 

Mitsubishi Power Systems, Inc. Presentation 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 Poster 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. of

Canyon Energy Project. D. Kirk of Fuel Tech Inc. to C. McFarlin of California Energy 

Commission, September 3, 2008. 
Draft Final Staff Report – NOx RECLAIM 136 

October 6November December 4, 2015 

12. Influence Factors and Control Research on Ammonium Bisulfate Formation in the Process of 

Selective Catalytic Reduction. 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. LoTOxTM – Novel NOx Control Solution. Naresh J Suchak, Ph.D., Monica Caldwell, Peter 

Studer, Frank R Fitch, Ph.D., Linde Gases. Paper #33612. A&WMA’s 107th 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 Levels of Nitrogen Oxide from Refinery Gases. S. Harrison, N. 

Suchak, F. Fitch, Linde Gases. www.digitalrefining.com/article/1000954. PTQ Q3 2014 

17. Wet Scrubbing-based NOx Control Using LoTOx Technology – First Commercial FCC StartUp Experience. Nicholas Confuorto of BELCO Technologies, Jeffrey Sexton of Marathon 

Petroleum Company LLC. www.digital refining.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. Whitlock, S. Myer of MECS Dupont. June 4, 2014. 
Draft Final Staff Report – NOx RECLAIM 137 

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 & Development 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. 
Draft Final Staff Report – NOx RECLAIM 138 

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 installed cost (TIC) calculation and present worth value (PWV) estimation 

methodologies used in the staff and NEC cost effectiveness 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 EPA cost model with a 150 percent contingency. 
Draft Final Staff Report – NOx RECLAIM 139 

October 6November December 4, 2015 

The second approach used the NEC model for the manufacturer’s SCR designed 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% higher than that estimated using the actual costs 

submitted by Refinery 1. 

x Staff scaled the Refinery 1 SCR PWV cost using 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. 
Draft Final Staff Report – NOx RECLAIM 140 

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 factors applied, the 

manufacturer’s 2-layer model was approximately 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 provided 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 refineries 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 

(103

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
Draft Final Staff Report – NOx RECLAIM 141 

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 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 same cost assumptions stated 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, 103 Barrels/Day 58 68 60 79 79

Feed rates reported in SOx RECLAIM, 103Barrels/Day 30 55 55 71 90

Feed rates shown in the Jan 22 14 Working Group Meeting, 34 49 52 67 84

103Barrels/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 determined 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). 
Draft Final Staff Report – NOx RECLAIM 142 

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 

(103 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 range between $18K and $20 K per ton of NOx reduced. 

Using the NEC 3-Layer approach, the upper value of CE would be $29K. 
Draft Final Staff Report – NOx RECLAIM 143 

October 6November December 4, 2015 

Appendix G - Comparative Analyses for Boilers & Heaters 

This appendix provides a comparison of the control equipment design configuration, total installed 

cost (TIC) calculation and present worth Value (PWV) estimation used in the staff and NEC 

estimations for the boiler and heater cost effectiveness calculation. Table G.1 summarizes the 

basic comparison. Variations in the selective catalytic reduction (SCR) 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 design 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 by the refineries for SCRs 

that achieved 1.6 – 3.5 ppmv NOx was used. The refineries provided actual 

equipment costs, total installed costs (TIC) and annual operating costs. The 
Draft Final Staff Report – NOx RECLAIM 144 

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 the actual cost data in Group 1, PWV = 

1.052 x TIC. 

o Group 3 data set: Equipment costs 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 reported costs for a 650 mmBtu/hr heater was about 

$42 M and the upperbound PWV that staff derived 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 Appendix 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 system and induced draft fan installation. 
Draft Final Staff Report – NOx RECLAIM 145 

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, increased 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) 
Draft Final Staff Report – NOx RECLAIM 146 

October 6November December 4, 2015 

Summary and Discussion 

The two methodologies employed to develop the PWVs for SCRs are inherently different. The 

resulting number of units determined to be cost 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 achieved-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 proposing 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 Table G-2. By comparison, the Refinery 1 FCCU SCR 

has 2 layers of catalyst with a total catalyst depth 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.
Draft Final Staff Report – NOx RECLAIM 147 

October 6November December 4, 2015 

Table G. 1 – Performance Levels and Dimensions 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 reformers 

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 
Draft Final Staff Report – NOx RECLAIM 148 

October 6November December 4, 2015 

Appendix H - Comparative Analyses for SRU/TGUs 

This appendix provides a comparison of the proposed control equipment design configuration, 

total installed cost (TIC) calculation and present worth Value (PWV) estimation used in the staff 

and NEC estimations for the SRU/TGTU cost effectiveness calculation. Table H.1 summarizes the 

basic comparison. Staff evaluated selective catalytic reduction (SCR), LoTOx, and Know-NOx

technologies while NEC expressed concerns on the 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 SCR, LoTOx, and KnowNOx were 

analyzed. SCR and LoTOx are used in refinery applications 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 
Draft Final Staff Report – NOx RECLAIM 149 

October 6November December 4, 2015 

OAQPS Guideline methodology were used to estimate the 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 provided 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 cover 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 layers (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 establish a distribution that was the 

basis for a power law cost curve. (See Addendum-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 assessments revolves around the selection of control 

equipment analyzed. The SCAQMD analysis included multiple control technologies while NEC 

analysis relied solely on SCR implementation where design options and costs were prorated for 

the SRU/TG applications. Additionally, costs associated 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 threshold for inclusion in the calculation of potential BARCT emission 

reductions from SRU/TGUs. 
Draft Final Staff Report – NOx RECLAIM 150 

October 6November December 4, 2015 

A second major difference between the two assessments 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 that 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 NEC which resulted in closing the gap between the 

two analyses. 
Draft Final Staff Report – NOx RECLAIM 151 

October 6November December 4, 2015 

Appendix I - Comparative Analyses for Coke Calciners

This appendix provides a comparison of the NOx emissions control design configuration, total 

installed cost (TIC) calculation and present worth Value (PWV) estimation used in the staff and 

NEC estimations for the Coke Calciner cost effectiveness 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 side by 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 estimate 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 used the costs provided to staff, and applied a 

factor of 4.67 to cover uncertainty in process development and installation costs. As a result, TIC 

= 4.67 x Equipment costs. Ultra-Cat was not considered a solution for the coke calciner. 

Summary 
Draft Final Staff Report – NOx RECLAIM 152 

October 6November December 4, 2015 

Staff agrees that the coke calciner is a challenging 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. 
Draft Final Staff Report – NOx RECLAIM 153 

October 6November December 4, 2015 

Appendix J - Comparative Analyses for Turbine/Duct 

Burners 

This appendix provides a comparison of the control 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 NEC recommendation was to add catalyst to achieve 

the 2 ppmv targeted emissions limit. 
Draft Final Staff Report – NOx RECLAIM 154 

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 
Draft Final Staff Report – NOx RECLAIM 155 

October 6November December 4, 2015 

Appendix K – Co-Benefits of Energy Efficiency Projects 

Table K.1 below summarizes NOx reductions that are 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 and Co-Benefits Assessment of Large Industrial 

Sources – Refinery Sector Public Report, June 6, 2013. 

CARB approved the Energy Efficiency and Co-Benefit Assessment of Large Industrial Facilities 

(EEA Regulation) on July 22, 2010. The regulation required the largest industrial sources in 

California to conduct a one-time assessment of fuel and energy consumption, and emissions of 

greenhouse gas, criteria pollutants, and toxic air contaminants. Affected facilities were also 

required to identify potential improvements in equipment, 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 the EEA Regulation. Phase 1 was to 

develop the industrial sector public 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 actual emission reductions would be different from the 

estimates in the report, and CARB had no plan to count these estimates as reductions to the current 

air quality. Thus, staff did not count the reductions in this proposal. 
Draft Final Staff Report – NOx RECLAIM 156 

October 6November December 4, 2015 

Table K. 1- Summary of Emission Reductions and 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 2009-11 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) 
Draft Final Staff Report – NOx RECLAIM 157 

October 6November December 4, 2015 

Appendix L – Survey Questionnaires for Refinery Sector 

In June 2013, staff developed Survey Questionnaire to collect pertinent information for the NOx 

RECLAIM rule development. The Survey Questionnaire was sent to the 37 top emitting facilities 

and California Portland Cement 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 information 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 
Draft Final Staff Report – NOx RECLAIM 158 

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% O2 or ppmv at 15% O2). 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, installation costs, and annual operating costs) 

g. Installation date (e.g. July 2005) 

6. Provide drawings that show location and distances between the 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, oxygen, 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, installation costs, and annual operating costs) 

f. Installation date (e.g. July 2005) 

Reports Submitted Under the U.S. EPA Consent Decree 
Draft Final Staff Report – NOx RECLAIM 159 

October 6November December 4, 2015 

9. If the facility must install control technology to reduce the NOx emissions under an U.S. 

Environmental Protection Agency (EPA)’s consent 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 gases. Provide a brief description of the control approach,

manufacturer's name, estimated emission 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. 
Draft Final Staff Report – NOx RECLAIM 160 

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 Appendix S that discuss 1) the NOx control 

technologies, 2) costs and cost effectiveness analyses 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-refinery facilities are included in Appendix T. 
Draft Final Staff Report – NOx RECLAIM 161 

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 highest 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 considered clinker and is cooled, 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 flue 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 gases 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
Draft Final Staff Report – NOx RECLAIM 162 

October 6November December 4, 2015 

Control Technology 

Long, dry cement kilns have achieved NOx reductions 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 along the 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 reduction system (SNCR) 

before it ceased operation. This approach involves injecting 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 treatment of NOx. With a long, dry cement kiln, this 

is often difficult to achieve with the different temperature 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 that of a new precalciner kiln using SNCR for NOx 

control. 

After discussions with several vendors, there is more than one technology available for effective 

treatment of NOx from this source category beyond the Tier 1 level. To effectively achieve the 

most significant NOx reduction, selective 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 installation at Mergelstetten has been in operation since 2010. An 
Draft Final Staff Report – NOx RECLAIM 163 

October 6November December 4, 2015 

SCR has also been installed on a long, dry kiln in Joppa, 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 the 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 
Draft Final Staff Report – NOx RECLAIM 164 

October 6November December 4, 2015 

solution, typically caustic, as the absorbing agent for SO2. The absorbed SO2 is converted to 

sulfates and sulfites which are then captured in the liquid effluent treatment system where they are 

separated and then disposed. Solid particulates in the flue gas 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. Temperature 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 

SO2 and preventing the formation of ammonium bisulfate (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 SO2 is present in the flue gas stream, the minimum SCR process temperature is determined 

by the formation of ABS. With the removal of SO2 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 BARCT level 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 an emission level of about 0.5 pounds of NOx per ton 

of clinker produced. 

The emission reductions achieved from the two long, dry cement kilns, based on the 2008 

compliance year baseline emissions, amount to 1.29 tons per day. This is the incremental 

reduction from the Tier 1 emission level. 
Draft Final Staff Report – NOx RECLAIM 165 

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 equipment costs include the SCR equipment, ductwork, 

steel, electrical, ammonia 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 plot space 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 engineering 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 will 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, housing, dust collection hoppers), wet 

gas scrubber systems (venturi scrubber, pumps, structural 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 operating 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. 
Draft Final Staff Report – NOx RECLAIM 166 

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 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) requires 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 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 

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 effectiveness 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 
Draft Final Staff Report – NOx RECLAIM 167 

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 the 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 costs 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 
Draft Final Staff Report – NOx RECLAIM 168 

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 normal 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 reheat the 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 three vendor estimates. In addition, 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 were also 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 for flue gas treatment of cement kilns are 

considered feasible and cost effective. 
Draft Final Staff Report – NOx RECLAIM 169 

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 Ceramic 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 Selective Catalytic Reduction on Cement Kilns for Multi-Pollutant 

Control. Armendariz, A. Department of Environmental 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 Agency, 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 and Standards. 2002; EPA/452/B-02-001. 
Draft Final Staff Report – NOx RECLAIM 170 

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 Container 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 fuel 

firing. 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 for 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 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. 
Draft Final Staff Report – NOx RECLAIM 171 

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. This 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 level 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 level for container glass melting furnaces 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 a NOx emission 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 equipment costs were scaled from an existing vendorbased installation quotation for a sodium silicate glass melting furnace. 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 chemical 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 scaled by the heat input rate. The annual operating 

costs (also scaled by heat input rate) 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 will be required. This system would replace 

the existing dry scrubbing system and electrostatic precipitators (ESPs) at this facility. 
Draft Final Staff Report – NOx RECLAIM 172 

October 6November December 4, 2015 

For an SCR installation, two scenarios were considered. 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 which one ESP is operated as a backup. In the 

second scenario, one SCR would handle the exhaust from each ESP, so there would be a total of 

three SCR systems installed. 

The vendor-based costs for the first option include 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 extra space for a second layer, supporting structure, 

ammonia skid, and programmable logic control (PLC) 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 an elevated 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 include the engineering, fabrication and field 

installation of three SCR chambers as described 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 ductwork to and from the existing stacks. The annual operating 

costs were also derived as described 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 considered for this approach. The first option would 

include the installation of two SCR systems, each sized 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 number of additional units required for each of the 

two options. Also for each option, a 15% contingency factor was applied to the direct and indirect 

costs. The annual operating costs for each option include operations and maintenance 

labor/materials, ammonia consumption, power consumptions and catalyst costs. In addition, an 

indirect annual cost factor was added and was calculated to be the capital costs multiplied by the 

capital recovery factor (CRF) for a 25 year installation at a 4% interest rate. 
Draft Final Staff Report – NOx RECLAIM 173 

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) requires 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 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
Draft Final Staff Report – NOx RECLAIM 174 

October 6November December 4, 2015 

To achieve an 80% reduction, the cost effectiveness 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 technologies 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 calculation of the installation 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 stacks for both options (single and three SCRs). 

Operation and labor costs were added to the annual costs for both options as well as costs for power 

consumption with the addition of a booster fan. The annual catalyst replacement 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 with 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 SO3 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 would not result in ABS formation as long as the 
Draft Final Staff Report – NOx RECLAIM 175 

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 point 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 complex 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 reduction technologies for flue gas treatment of 

container glass melting furnaces are considered feasible and cost effective. 
Draft Final Staff Report – NOx RECLAIM 176 

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 chambers. 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

(14,5522,859)

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 
Draft Final Staff Report – NOx RECLAIM 177 

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 Ceramic 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 and 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. 
Draft Final Staff Report – NOx RECLAIM 178 

October 6November December 4, 2015 

Appendix O– Sodium Silicate Furnace 

Process Description 

In the NOx RECLAIM program there is only one facility 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 melting 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, however, selective catalytic reduction (SCR) is the 

technology that is best suited for significant 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 
Draft Final Staff Report – NOx RECLAIM 179 

October 6November December 4, 2015 

to produce nitrogen and water vapor. The typical 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 pounds per ton of glass pulled, effective in 1992. 

The 2005 NOx RECLAIM amendment proposed no new 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 emission 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 equivalent to the Tier 1 emission level for 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 include the SCR chamber, one layer of catalyst with 

extra space for a second layer, supporting structure, 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, which for this installation were conservatively 
Draft Final Staff Report – NOx RECLAIM 180 

October 6November December 4, 2015 

assigned an annual replacement interval. In addition, 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 operating 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 SOx 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) requires 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 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 silicate 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 silicate furnace are considered cost effective. 
Draft Final Staff Report – NOx RECLAIM 181

October 6November December 4, 2015 

Review of ETS’s Analysis for 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 installation of the control equipment. 

For both vendor estimates, a contingency of 15% was applied the total direct and indirect capital 

costs. For the Vendor 2 estimate, the capital costs pertinent to SO2 treatment were removed since 

this system would be removing NOx only. 

To achieve the proposed BARCT level, the revised 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 considered 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 
Draft Final Staff Report – NOx RECLAIM 182 

October 6November December 4, 2015 

References for Sodium Silicate Furnace 

1. World’s Largest Supplier of Ceramic 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 and Standards. 2002; EPA/452/B-02-001. 
Draft Final Staff Report – NOx RECLAIM 183 

October 6November December 4, 2015 

Appendix P – Metal Heat Treating Furnaces >150 

MMBTU/hr 

Process Description 

In the NOx RECLAIM program there is one facility that operates these furnaces among the top 

37 facilities. For the 2005 NOx RECLAIM amendment, 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 Heat 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 burner 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 are 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 reduction, 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 typical operating temperature of the exhaust gas is 

between 450 and 850 degrees F. 
Draft Final Staff Report – NOx RECLAIM 184 

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% O2 (0.073 lb/MMBTU). This rule was adopted in 2008 to address NOx emissions from 

miscellaneous sources. The 2005 NOx RECLAIM amendment proposed a BARCT level of 45 

ppm at 3% O2 (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% O2.

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 source category incremental emission reductions 

achieved from the metal heat treating furnaces 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 installation costs include the SCR catalyst, reactor and 

ductwork, ammonia skid, dilution air fan, civil work, and installation. A contingency value of 

200% of the SCR equipment costs was used to estimate the installation, foundation, civil work, 

and other construction uncertainties. The annual operating costs include ammonia consumption, 

catalyst replacement costs (2 year replacement interval), power consumption, and maintenance. 

The existing equipment-based equipment costs include installation, SCR catalyst system, ammonia 

skid, and control system. A 60% contingency value 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) 
Draft Final Staff Report – NOx RECLAIM 185 

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) requires 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 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

Existing 

equipmentbased 

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 furnaces is considered cost effective. 

Review of ETS’s Analysis for Metal 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. 
Draft Final Staff Report – NOx RECLAIM 186 

October 6November December 4, 2015 

References for Metal Heat Treating Furnaces >150 MMBTU/hr 

1. EPA Air Pollution Control Cost Manual. United States Environmental Protection Agency. 

Office of Air Quality Planning and 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. 
Draft Final Staff Report – NOx RECLAIM 187 

October 6November December 4, 2015 

Appendix Q – Non-Refinery, Non-Electrical Electrcity 

Generating Facility Stationary 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, Rule 1134 limits the NOx emissions for all gaseous and 

liquid-fueled engines that are above 0.3 MW. Gas turbines operate either in simple cycle or 

combined cycle. Simple cycle units use the mechanical 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 natural 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 electric utility power). Some of these units are 

cogenerating units that, in addition 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 has remained unchanged since 2000 (Tier 1), which 

equates to 0.06 lb/MMBTU. 

Current Emission Inventory 

Among the top thirty seven non-electrical electricity generating facility NOx emitting 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 fired on diesel or process gas, have the highest 

NOx emission concentrations in this source category. Six of these units are operated on an 

offshore oil drilling platform (outer continental shelf, or OCS). 
Draft Final Staff Report – NOx RECLAIM 188 

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% O2 

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 turbines, 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 
Draft Final Staff Report – NOx RECLAIM 189 

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 conditions, 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 BARCT for gas turbines, so these units have 

been only required to meet the Year 2000 Tier 1 emission level. The Tier 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% O2. 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 generating facility, non-refinery gas turbines in the top 37 

facilities and based on vendor discussions and achieved in practice BACT installations, the 

proposed BARCT level for this source category is 2 ppm @15% O2, 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 achievable 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 achieve 8 ppm at a 95% reduction for their current 

emission level since they have the highest emissions. The offshore gas compression turbines can 

achieve 5 ppm at a 95% reduction. A 2 ppm level would be achievable 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 BARCT 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. 
Draft Final Staff Report – NOx RECLAIM 190 

October 6November December 4, 2015 

The emission reductions achieved from both subsets 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 costs 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 installation 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% 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 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) requires 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. 
Draft Final Staff Report – NOx RECLAIM 191 

October 6November December 4, 2015 

The cost effectiveness for non-electrical 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 gas 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 meeting 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
Draft Final Staff Report – NOx RECLAIM 192 

October 6November December 4, 2015 

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

Review of ETS’s Analysis for Metal 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 the cost estimates were made. 
Draft Final Staff Report – NOx RECLAIM 193 

October 6November December 4, 2015 

References for Non-Refinery, Non-Electrical Electrcity Generating 

Facility Stationary Gas Turbines 

1. Best Available Retrofit Control Technology 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 and 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 Presentation, Luke Cowell, June 6, 

2012.

5. Catalog of CHP Technologies: Combustion Turbines. United States Environmental 

Protection Agency - Combined Heat and Power Partnership, March 2015. 

6. Alternative Control Techniques Document – NOx Emissions from Stationary Gas Turbines. 

U.S. Environmental Protection Agency, Office of 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. 
Draft Final Staff Report – NOx RECLAIM 194 

October 6November December 4, 2015 

Appendix R – Non-Refinery Stationary Internal Combustion 

Engines 

Process Description 

Stationary Internal Combustion Engines (ICEs) are 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 rich or lean conditions, depending on the air to fuel 

ratio. Rich combustion corresponds to an air /fuel ratio that is fuel-rich while lean combustion 

corresponds to a fuel-lean air/fuel ratio. Small SI engines typically run as rich burn, but many 

larger units as well as CI engines operate under lean conditions. 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 engines are fired on liquid fuels such as diesel. 

In 2005, there was no new BARCT proposed for this source category. Consequently, the emission 

factor has remained unchanged since 2000 (Tier 1), which equates to about 57 ppm at 15% O2 for 

natural gas-fired engines. During the 2008 amendment 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% O2 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 lean 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. 
Draft Final Staff Report – NOx RECLAIM 195 

October 6November December 4, 2015 

Table R. 1 - 2011 Emissions for Internal Combustion Engines at Top 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 highest NOx emission concentrations in this source 

category. 2-stroke SI engines have higher NOx emissions 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 
Draft Final Staff Report – NOx RECLAIM 196 

October 6November December 4, 2015 

Control Technology 

The flue gas from rich burn engines is typically very low in excess oxygen. This enables NOx 

reduction to take place via Non-Selective Catalytic Reduction technology (NSCR), which is 

inexpensive, readily installed, and simultaneously 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 reduces 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 content 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 Reduction (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 and 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 established a NOx emission level of 11 ppm @15% O2 for 

most IC engines. The technology identified for 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. NSCR is 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 the non-electrical electricity 

generating facility engines in the top 37 emitting facilities, the proposed BARCT level is 11 ppm 

@15% O2. 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 requirements by July 1, 2011, since these pollutants 

are not governed under RECLAIM rules. There is an added benefit with three way catalysts 

because they also control NOx and this has resulted in emission reductions for these engines. For 

lean burn engines, however, the control technology to achieve the NOx reductions is SCR. If all 

the non-OCS engines in this category were to achieve the proposed BARCT level, the emission 

reductions from the Tier 1 level would be 0.84 tons per day. There is a portion of this reduction 
Draft Final Staff Report – NOx RECLAIM 197 

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 these 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 engines provides a challenge with regards to very 

low allowable backpressures, which 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 often variable in load. SCR systems need a more 

constant load so that the proper operating temperatures 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 installation costs from an existing SCR installation 

on a lean-burn engine. The vendor-supplied costs were for 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 Orange 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 externally constructed platform because of the site 

constraints inside the engine building. These additional costs have been included as part of this 

analysis in anticipation of any supplemental support structures necessary to accommodate the SCR 

system. The 2009 dollar figures for the OCSD installation 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 costs for this installation at OCSD. 

The annual operating costs include catalyst replacement, reagent consumption, reagent delivery 

system maintenance, and electrical consumption. 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 
Draft Final Staff Report – NOx RECLAIM 198 

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% 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 engine 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) requires 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
Draft Final Staff Report – NOx RECLAIM 199 

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 with the achievability of the reductions using SCR 

technology and no changes to the cost estimates were made. 

References for Non-Refinery Stationary Internal Combustion 

Engines 

1. EPA Air Pollution Control Cost Manual. United States Environmental Protection Agency. 

Office of Air Quality Planning and 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 – NOx Emissions from Stationary Reciprocating 

Internal Combustion Engines. U.S. Environmental Protection Agency, 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 County Sanitation District, July 2011. 
Draft Final Staff Report – NOx RECLAIM 200 

October 6November December 4, 2015 

Appendix S – Non-Refinery Boilers >40 MMBTU/hr 

In the top 37 emitting facilities, there are four boilers that are above 40 MMBTU/hr. They range 

between 49 and 247.3 MMBTU/hr. The 2005 BARCT level for these units was 9 ppm at 3% O2.

The incremental NOx reduction going from 9 ppm to a proposed BARCT level of 2 ppm would 

be 0.01 tons per day. 

SCR would be the technology of choice for achieving 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 present worth value for the largest unit 

was calculated from the cost curve developed for 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
Draft Final Staff Report – NOx RECLAIM 201 

October 6November December 4, 2015 

Appendix T – Survey Questionnaires 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 information 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% O2 or ppmv at 15% O2). 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: 
Draft Final Staff Report – NOx RECLAIM 202 

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 the major and large NOx sources 

at the facility. 

Reports Submitted Under the U.S. EPA Consent Decree 

7. If the facility must install control technology to reduce the NOx emissions under an U.S. 

Environmental Protection Agency (EPA)’s consent 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 gases. Provide a brief description of the control approach, 

manufacturer's name, estimated emission 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. 
Draft Final Staff Report – NOx RECLAIM 203 

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 staff’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 sector. Staff’s calculation were also 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 emissions, and Appendix W contains the 2012 baseline emissions for 

electrical electricity generating facilities. 
Draft Final Staff Report – NOx RECLAIM 204 

October 6November December 4, 2015 

Appendix U – Staff’s Proposal and CEQA Alternatives 

Staff has considered several options to determine 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 the 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. With these 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 affect four 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 requirements for their equipment, which is mostly at 

BACT. Staff is proposing a Regional NSR Holding 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 applied 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 conditions 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 adjustments, 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 adjustments and the total RTC reduction. 
Draft Final Staff Report – NOx RECLAIM 205 

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 

Proposal 

TPD (Tons Per Day) 

The staff proposal for the shave would affect the 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 and 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. 
Draft Final Staff Report – NOx RECLAIM 206 

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
Draft Final Staff Report – NOx RECLAIM 207 

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-Electrical Electrcity Generating 

Facilities 26 

B2 

Top 90% Holder, Electrical Electrcity Generating 

Facilities 21 

TOTAL 57 
Draft Final Staff Report – NOx RECLAIM 208 

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 Refinery (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 Electrcity 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 across 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 approach and 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 proposed BARCT level would be subtracted from the 

base year emissions at the previous BARCT level (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, with investors grouped with the major refineries. RTC holdings for major 

refineries and investors would be shaved by 66 percent. For non-major refineries and all other 

facilities, the RTC holdings would be shaved by 37 percent. 

Table U.3 - NOx RECLAIM Shave Options 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 

667% 

(9 Facilities) 

496% 

(26 Facilities) 

496% 

(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% 
Draft Final Staff Report – NOx RECLAIM 210 

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 facilities 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 subject to 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 presented 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 remaining RTC for the Table 7 

and Table 8 facilities are as follows: 

Compliance 

Year 

Table 7 Facilities Table 8 Facilities 

Reductions 

(TPD) 

Ai

Remaining 

(TPD) 

Reductions 

(TPD) 

Bi

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 = Ai/14.57 

Table 8 Facilities = Bi/9.09 
Draft Final Staff Report – NOx RECLAIM 211 

October 6November December 4, 2015 

The Non-tradable/Non-usable NOx Adjustment Factor 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 Non-tradable/Non-Usable holdings would be as 

follows: 

Compliance 

Year 

Table 7 Facilities 

RTC Reductions 

Table 8 Facilities 

RTC Reductions 

Annual (Ci)

(TPD) 

Adjustment 

Factor 

Annual (Di)

(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 = Ci/14.57 

Table 8 Facilities = Di/9.09 

Regional NSR Holding Account 

In addition to the Non-tradable/Non-usable account, 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 account under specific circumstances, which will be 

funded by the shaved portion of each affected facility’s holdings for every compliance year of the 

shave beginning in 2017. At the end of the shave, 49% of the holdings from newer electrical 

electricity generating facilities subject to NSR requirements 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-tradable 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 cumulative holdings that will go into the account: 
Draft Final Staff Report – NOx RECLAIM 212 

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 the Regional NSR Holding Account 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 specific 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. 
Draft Final Staff Report – NOx RECLAIM 213 

October 6November December 4, 2015 

Appendix V – 2011 Audited Emissions of 20 tons per day 

The 2011 audited NOx emissions for the 281 facilities 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 
Draft Final Staff Report – NOx RECLAIM 214 

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 
Draft Final Staff Report – NOx RECLAIM 215 

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 
Draft Final Staff Report – NOx RECLAIM 216 

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 
Draft Final Staff Report – NOx RECLAIM 217 

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 
Draft Final Staff Report – NOx RECLAIM 218 

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 
Draft Final Staff Report – NOx RECLAIM 219 

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 
Draft Final Staff Report – NOx RECLAIM 220 

October 6November December 4, 2015 

Appendix W – 2012 Emissions 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 category due to the uniqueness of its operations. There 

have been several changes within recent years that have warranted the use of more recent base 

year data. 

The San Onofre Nuclear Generating Station (SONGS) has not been in operation since early 2012 

and is now undergoing decommissioning. The power deficit was to be made up 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 the same amount of power as their predecessors. 

Other trends in the industry have begun to affect power 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 volatility of these renewable energy sources means 

that gas demand must be met almost in real time. 

The growth factor for electrical 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 in the future is set to decrease slightly due 

to the utilization of more efficient electrical electricity 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 growth factors from SCAG (Southern California 

Association of Governments) for non-electrical 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 emissions include those for the major sources only 
Draft Final Staff Report – NOx RECLAIM 221 

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 Emissions 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 tables in the 2104 2014 California Gas Report and it 

shows a slight decrease in demand for natural gas. 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. Per 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 brought to SCAQMD staff’s 

attention their concern about the shave and whether a power generating facility can still comply 

with its emission allocation and NSR demonstration concurrently, especially when there is no cost 

effective method to retrofit their equipment to generate credits. 

SCAQMD staff has proposed a safety valve for addressing the concerns of the power electricity 

generating sector. A Regional NSR Holding Account has been proposed that would consist of 

RTCs solely to meet the programmatic NSR holding 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 experienced and there is an added demand for power 

production. SCAQMD staff has also proposed to allow access to the Regional NSR Holding 

Account if the Governor declares a state of emergency. 
Draft Final Staff Report – NOx RECLAIM 222 

October 6November December 4, 2015 

Appendix X – Proposed Changes 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 EGFs 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 for 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 used to satisfy any NOx requirements for 

continuing obligations under Regulation XIII – New Source Review. If needed 

to equal this amount, any Non-tradable/Non-usable RTCs and any RTCs 
Draft Final Staff Report – NOx RECLAIM 223 

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 all 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 EGFs under common control would have 

one opportunity to apportion the NOx emission 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 generated 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 must be limited to the amount of RTCs 

required to be held for that source pursuant to Rule 2005 as of the date of the 

opt-out plan submittal. 
Draft Final Staff Report – NOx RECLAIM 224 

October 6November December 4, 2015 

• Subdivision (j) shall not be applicable to the EGF for any equipment installed 

or modified after the date of approval 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 comply with the requirements of Rule 2012 

– Requirements for Monitoring, Reporting, and Recordkeeping for Oxides of 

Nitrogen (NOx) Emissions and its associated protocols unless the Executive 

Officer has approved an alternative monitoring 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 expired, 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 Officer 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 to ensure proper compliance as specified above 

(also see subparagraphs (g)(2)(B) through (GH)). If, within 180 days or within the mutually 

agreed upon time period of receiving a complete opt-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 plan is effective upon issuance of a facility permit 

incorporating the conditions mentioned 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). 
Draft Final Staff Report – NOx RECLAIM 225 

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 Nitrogen (NOx) and Oxides of Sulfur (SOx). 

Rule 2002 provides an overview of the RECLAIM Allocations; 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 requirement for establishing High Employment/Low 

Emissions (HILO) facilities, Non-Tradable Allocation 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 amendments 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 threshold 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 reduced in equal increments of 2 tons per day 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 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 facilities 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. 
Draft Final Staff Report – NOx RECLAIM 226 

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 subparagraph. 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 focus 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 amendments focus on providing relief from 

burdensome New Source Review (NSR) holding requirement for newer electrical electricity 

generating facilities that entered 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 quantity 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 subparagraph (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 prices have not exceeded the proposed $22,500 per ton threshold as 

specified in subparagraph (f)(1)(I) and a State of Emergency related to electricity demand or power 

grid stability in the Basin as specified in paragraph (f)(4) has not been declared by the Governor, 

then the Non-tradable/Non-usable NOx RTCs for that compliance year, except for those RTCs 

specified in subparagraph (f)(1)(G), shall be submitted 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 RTCs holdings listed in Table 9 of this Rule 

from the corresponding facilities identified 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)
Draft Final Staff Report – NOx RECLAIM 227 

October 6November December 4, 2015 

A companion provision to the abovementioned subparagraphs is subparagraph (f)(1)(HG) which 

states that for the purposes of meeting the NSR holding requirement as specified in subdivision (f) 

of Rule 2005, the facilities identified in Table 9 may use a combination of their Tradable/Usable 

and Non-tradable/Non-usable RTCs specified in subparagraph (f)(1)(C) and the amount for each 

facility listed in Table 9 which represent the RTCs in the Regional NSR Holding account. 

Other than the updated price trigger, other proposed changes to subparagraph (f)(1)(I) require the 

Executive Officer to include in his report to the 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) and (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 determining allocations for 

existing facilities that enter RECLAIM. 

Staff is proposing to add RTC price thresholds 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-month 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 average staff will update the 3-month and once per 

month. [subparagraph (f)(1)(E)] 

Notwithstanding the requirements of non-tradable/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 Executive Officer will report the 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-usable NOx reductions RTCs, as specified in 

subparagraphs (f)(1)(DB) and (f)(1)(C) valid for the 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 
Draft Final Staff Report – NOx RECLAIM 228 

October 6November December 4, 2015 

determination to the Governing Board. For the purpose 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 refers 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 provisions to convert Non-tradable/Non-usable RTCSs

and the Regional NSR Holding Account during a State 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 State of Emergency, the current compliance year 

Non-tradable/Non-usable NOx RTCs held by any 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 exhausting 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 electrical electricity generating facility requesting NOx 

RTCs from the Regional NSR Holding Account would be required to submit a written request to 

the Executive Officer specifying the amount of RTCs 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 based 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 Basin, as declared by the Governor, was 

the direct cause of the excess emissions. 

(ii) The facility has been ordered to generate electricity in an increased 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. 
Draft Final Staff Report – NOx RECLAIM 229 

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 this report will be, as applicable: 

(i) the quantity of RTCs from the Regional NSR Holding Account that were 

distributed for compliance with the requirement to reconcile 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 RECLAIM after the date of adoption. For this rule provision for 

Compliance Year 2016 and all subsequent years the amount determined pursuant to subparagraph 

(d)(1)(A) except the variable B2 shall be the lowest of: 

(i) The applicable 2000 (Tier I) Ending Emission 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 subject source as specified in Table 3; and 

(iii) The proposed BARCT Emission factor for the subject as specified in Table 6. 

For those facilities that are permanently shutting 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 
Draft Final Staff Report – NOx RECLAIM 230 

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 with a 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 intention 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], Aany Facility Permit Holder of a facility listed in 

Table 7 or 8 permanently shutting down some or allone 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 deemed shut down and subject to the RTC and permit 

surrender requirements if it is non-operational for a period of two 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 economic 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݋ܶ =
Draft Final Staff Report – NOx RECLAIM 231 

October 6November December 4, 2015 

The requirements related to the abovementioned facility and equipment shutdowns would not

apply to shutdown equipment for which the equipment’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 Facility 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 requirements. 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 allocations 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 evaluation 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 have any 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 
Draft Final Staff Report – NOx RECLAIM 232 

October 6November December 4, 2015 

compliance year pursuant to Rule 2004 – 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 an existing 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-tradable credits. 

The offset requirements for new RECLAIM facilities remained unchanged. Thus a new facility 

will have to continue to hold adequate RTCs equal to the amount of emission increases at the 

beginning of each compliance year. Any unused 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 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 emissions in their Facility Permit, staff is proposing a 

Regional NSR Holing Account in Rule 2002. Proposed 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 multiplying 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. 
Draft Final Staff Report – NOx RECLAIM 233 

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 increase the initial SOx and/or NOx allocations quantified 

for them pursuant to Rule 2002. The longer the 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 Emission Standards includes a row for Diesel 

Combustion, which includes a BARCT Emission Standard of “15 ppmv as required under Rule 

431.2.” However, the standard in Rule 431.2 is actually “15 ppm by weight” rather than 15 ppmv 

(i.e., 15 ppm by volume). The staff proposal would correct 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 due to Extenuating Circumstances 

Rules 2011 – Requirements for Monitoring, Reporting, and Recordkeeping for Oxides of Sulfur 

(SOx) Emissions and 2012 – Requirements for Monitoring, Reporting, and Recordkeeping for 

Oxides of Nitrogen (NOx) Emissions set forth 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 Monitoring, 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 Assessments 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 are required to perform RATAs on a semi-annual 

basis within six months of the end of the calendar 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) 
Draft Final Staff Report – NOx RECLAIM 234 

October 6November December 4, 2015 

emission rate measurement system measured during 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 equipment 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 inoperable. 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 basis, 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-operational status. The inherent 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 were 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 postponement for unforeseen equipment failure 

would apply separately for each unrelated, independent 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 would 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 generating facilities under contractual obligation with 

CalISO to have equipment available or owned and operated by municipalities that did not operate 
Draft Final Staff Report – NOx RECLAIM 235 

October 6November December 4, 2015 

long enough to conduct a RATA during the quarter in which it is due, the semi-annual or annual 

assessment could be postponed to the next calendar quarter provided 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 prevents 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 for Semi-Annual Assessments to be performed for 

equipment monitored by CEMS. The purpose of these 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 conduct 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 operating 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 revise 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 showing no fuel flow are maintained on site. 

There were concerns from operators that for some units, disconnecting the fuel feed lines was not 

feasible. Alternatively, an operator can open the fuel strainers to accomplish the same goal. That 
Draft Final Staff Report – NOx RECLAIM 236 

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 not available to verify no 

fuel flow, SOx (NOx) emissions would be required 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) emissions 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 performing and passing the semi-annual or annual 

assessment. 

For electrical electricity generating facilities either having contractual agreements with CalISO to 

have their major source available but not necessarily operating, yet not having sufficient hours to 

conduct RATA testing or owned and operated by a municipality, amended rule language is being 

proposed to allow the postponement of the semi-annual or annual assessment to the next calendar 

quarter, provided that the facility demonstrates: 

x the semi-annual or annual assessment 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 adopted, also make the following typographical clarifications and 

corrections: 
Draft Final Staff Report – NOx RECLAIM 237 

October 6November December 4, 2015 

x Under Rules 2011 and 2012 Appendix A, Attachment C B.2.b the word “unit” would be 

added to offer clarity regarding the time period 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, Paragraph 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, Paragraphs 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, Attachment E and 2012, Appendix A, 

Attachment F – Clarification of “Standard Gas Conditions” 

Standard Gas Conditions is defined in Rule 2011, 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, defines standard conditions for SCAQMD purpose of 

SCAQMD purposes other than RECLAIM as “a gas temperature of 60 oF and a gas pressure of [1 

atmosphere].” Similarly, the natural gas industry 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 conversion is quite simple (multiplication 

by a constant factor of 1.015), it sometimes causes confusion 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 readily available for converting from actual conditions 

to the 60 oF standard but not to the 68 oF standard. The proposed amendments to Rule 2011, 

Appendix A, Attachment E and 2012 Appendix A, Attachment 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 consistently throughout the facility for RECLAIM purposes. 
Draft Final Staff Report – NOx RECLAIM 238 

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 
Draft Final Staff Report – NOx RECLAIM 239 

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 
Draft Final Staff Report – NOx RECLAIM 240 

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 OFFSET 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 OFFSETS 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 
Draft Final Staff Report – NOx RECLAIM 241 

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 OFFSET 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 
Draft Final Staff Report – NOx RECLAIM 242 

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 OFFSHORE 

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 
Draft Final Staff Report – NOx RECLAIM 243 

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 
Draft Final Staff Report – NOx RECLAIM 244 

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 
Draft Final Staff Report – NOx RECLAIM 245 

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 appreciates all the stakeholder input. 

More recent comment letters have been numbered and individual comments within each letter 

have been bracketed and numbered. 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 Engineering letter dated August 10, 2015 

Comment Letter #3 Norton Engineering letter dated September 4, 2015 

Comment Letter #4 Industry Coalition letter dated August 21, 2015 

Comment Letter #5 Latham & Watkins letter dated August 20, 2015 

Comment Letter #6 Yorke Engineering, 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 Services letter dated August 28, 2015 

Comment Letter #10 Charles F. Timms, 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 Smith email 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 Casey email dated September 24, 2015 
Draft Final Staff Report – NOx RECLAIM 246 

October 6November December 4, 2015 

Comment Letter #1 – WSPA’s Letter and Phillips 66’s Letter Dated August 21, 2015 
Draft Final Staff Report – NOx RECLAIM 247 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 248 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 249 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 250 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 251 

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Draft Final Staff Report – NOx RECLAIM 252 

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Draft Final Staff Report – NOx RECLAIM 253 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 254 

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Draft Final Staff Report – NOx RECLAIM 255 

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Draft Final Staff Report – NOx RECLAIM 256 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 257 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 258 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 259 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 260 

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Draft Final Staff Report – NOx RECLAIM 261 

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Draft Final Staff Report – NOx RECLAIM 262 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 263 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 264 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 265 

October 6November December 4, 2015 
Draft Final Staff Report – NOx RECLAIM 266 

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 Coalition’s letter and comments 

attached to the Draft Socioeconomic Staff Report. 

Response 1-2 Shave Methodology and Arbitrary Removal of Unused RTCs 

Staff disagrees with the commenter’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 date of 2014 or the revised 

attainment date of 2015. Thus, staff is obligated to find all technological 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 expeditiously as possible. Control Measure CMB-01 

is a control measure in the 2012 AQMP that called for a total NOx reduction of 3-5 tpd in 2 phases: 

2-3 tpd in Phase I with implementation date in 2014 (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 substantial 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 equivalent 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 triggered” 

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 
Draft Final Staff Report – NOx RECLAIM 267 

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 removing 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. Additional reduction from implementation 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 assessment, Control Measure CMB-01 from the 2012 AQMP 

does not prescribe how the shave should be calculated and thus it is not in conflict with the shave 

methodology. The proposed shave in the RECLAIM 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 growth 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 reduced the shave by 0.85 tpd to account for uncertainties and provide 

some additional compliance margin. The total shave 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 directly attributable to technology advancement 

(8.77 tpd) but not the unused RTCs. The unused RTCs 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 ton compared to the average cost-effectiveness 

10 Table 1.1 of the Preliminary Draft Staff Report 
Draft Final Staff Report – NOx RECLAIM 268 

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 emissions 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 surplus 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 required 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 unused RTCs, 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 and facilities must use missing data procedures to 

calculate emissions which may be higher than actual emissions. Also, facilities may underestimate 

their actual emissions and need to hold a stream of RTCs to account for 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. Staff 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 miscellaneous 

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 @ 2005 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. 
Draft Final Staff Report – NOx RECLAIM 269 

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 meet the 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 has discussed this issue with the U.S. EPA to 

seek their approval on the concept and receive feedback on whether or not 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 allocations were estimated based on the methodology described in Rule 

2002(e). There was no “across-the-board” uniform percentage shave. 

In the 2005 NOx RECLAIM amendment, a uniform 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. 
Draft Final Staff Report – NOx RECLAIM 270 

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 identified 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 emissions. 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 refinery 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-refinery 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-the-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 the 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 from the non-refinery sectors to refineries. While 

this occurs to some extent under the staff proposal, the effect would be greatly increased. 

For CEQA and socioeconomic analyses, staff considered 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 protect the environment, 

attain the NAAQS, satisfy state and federal CAA requirements and AQMP commitments, and at 

the same time, allow for economic growth, provide equity, and safeguards for the functioning of 

the RECLAIM program. 

With respect to the implementation time, because the implementation date for 2 tpd reductions in 

Phase 1 was due in 2014 and there are 5-8 tpd surplus RTCs in the market, staff believes that at a 

minimum 2 tpd reduction or up to 4 tpd reduction should be removed from the market no later than 

2016, not “back-loaded” to 2019 as the commenter suggested. As explained in Response 1-2, the 

removal of unused RTCs is expected to raise the RTC prices and stimulate the 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. 
Draft Final Staff Report – NOx RECLAIM 271 

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 that 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 analysis 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 RECLAIM amendment, staff has used a 25-year useful 

life for SCRs, LoTOx/scrubbers, and UltraCat applications. The commenter suggested that staff 

should have used a 10-year life since rule amendment 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 years 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 in the Bay Area were installed 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 district were installed in 1980-1990’s and are still in good operating 

conditions, and thus the Santa Barbara air district staff supports a 25-year useful life of control 

device. c) Staff found several BACT analyses for the air districts in Florida 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 such as SCRs, scrubbers, or LoTOx applications. 

17 Presented at the April 29, 2015 Working Group Meeting. 
Draft Final Staff Report – NOx RECLAIM 272 

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 experience. Even though the RECLAIM amendment 

was revised in 2005 and staff had estimated that the refineries would have to install 51 SCRs for 

refinery boilers/heaters by 2011, only 4 of these boilers/heaters were retrofitted with SCRs in 

responses to the EPA consent degrees or order of abatement. 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 removed in order to comply with the 2015 BARCT. 

Furthermore, BARCT requirements were not revised in 2005 for refinery gas turbines, refinery 

SRU/TGTUs, refinery boilers/heaters >40 – 110 mmbtu/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 procurement of control 

equipment, the total time interval between installations of control equipment 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 than catalytic 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 precipitators 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 NOx RECLAIM amendment; 4) a 25-year life was 

used for scrubbers in the 2010 SOx RECLAIM amendment; and 5) a 20- to 25-year life was used 

in Rule 1111. For other rules and regulations such as Rule 1146.1 and Rule 1147 that addressed 

low NOx burners, staff may use less than 25-year life depending on the type of control equipment 

and stationary sources. Finally, the commenter’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 control, 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 equivalent or greater reductions would be achieved 
Draft Final Staff Report – NOx RECLAIM 273 

October 6November December 4, 2015 

at `equivalent or less cost compared with 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.’ Yet, SCAQMD does not seek merely its determined BARCT 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 would be an actual NOx emission reduction of 8.77

tpd from the 2011-2012 activity levels at 2015 BARCT compared to the same activity levels 

at 2005 BARCT. This represents 8.77 tpd reductions in actual emissions. If the overall NOx 

RTC holdings had closely matched the total amount 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. However, 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 would first eliminate some, if not all, of these 

unused NOx RTCs from the market and only thereafter result in actual emissions reductions. 

Therefore, total emission reductions would be less than the BARCT-equivalent level of actual 

NOx emission reductions. The problem of excess unused 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 RECLAIM 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 available in the market, the RTC shave would need 

to be larger than the tons of emission reductions calculated for the BARCT analysis to induce 

an equivalent level of actual emission reductions. The proposed phased-in shave of 14 tpd is 

anticipated to be able to induce sufficient emission reductions by 2023 so that the expected 

total NOx emissions from the RECLAIM universe 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 comment 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 compliance options and the 

estimated control installation costs may not 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 
Draft Final Staff Report – NOx RECLAIM 274 

October 6November December 4, 2015 

emission sources, a RECLAIM facility has the flexibility of using RTCs to offset its facilitywide emissions and is expected to do so whenever 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 effectively 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 can 

be more cost-effectively achieved elsewhere. Therefore, emission credit prices in a wellfunctioning market must lie in between the upper 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 installation 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 control 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 where 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 applies, if at all, to the entire 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. 
Draft Final Staff Report – NOx RECLAIM 275 

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 interpretation. 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 rules 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 program shall be compared with those 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 made 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 program since its adoption. With the exception of the 

2000-2001 period when the California energy crisis took place, the historical discrete NOx 

RTC prices ($5,500 or lower per ton) 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 time economic gains for the RTC sellers; 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 emissions reductions achievable (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 emissions 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 
Draft Final Staff Report – NOx RECLAIM 276 

October 6November December 4, 2015 

beyond BARCT. For the same reason, it is a distorted 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 shave 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 should include the “value” of shaved RTCs is 

addressed below. 

In the 2005 RECLAIM amendments, some stakeholders 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 was first adopted and still disagrees today. 

Staff has never considered the “cost” of the shaved RTC’s to be recognized as a “cost” for 

determining equivalency with command and control. At the 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 RTCs 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 facility, 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 should not be considered as a compliance cost to 

be compared to the compliance cost under command-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 value 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 analysis 

of 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 
Draft Final Staff Report – NOx RECLAIM 277 

October 6November December 4, 2015 

from operational changes at refineries, which chose 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 shave amount was partially based on the BARCT 

analysis that included the installation of 51 SCR units at refineries. However, 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 achieved had they applied BARCT. As a result, there 

is a need to ensure that the currently proposed shave 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-equivalent 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 result, 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 implementation 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 differences 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 for 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 provide additional 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. 
Draft Final Staff Report – NOx RECLAIM 278 

October 6November December 4, 2015 

data to estimate cost. Staff believes its proposal was reasonable since its approach utilized 

information in the facility permits, information provided by the refineries through the Survey, and 

information provided by several prominent manufacturers of control 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 SCR catalysts for FCCU are not the same as the 

catalysts for boilers/heaters and SRU/TG applications. 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 emission reductions. In the socioeconomic 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. 
Draft Final Staff Report – NOx RECLAIM 279 

October 6November December 4, 2015 

NOx Feasible Level 

First, it is important to note that 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 BARCT are 1) technologically feasible and 2) costeffective. The feasible and cost-effective control technology must be considered BARCT even if 

they are not yet operational in the District. In this 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 commercialized control technology (i.e. technology 

that is either being offered commercially by vendors or is in commercial demonstration or 

licensing)20 . Staff can use a control technology that has been previously installed and operated 

successfully at a similar type of source, or has potential for application to the 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, the H&SC does not specify any threshold on the 

number of units that must be proven achieved-in-practice for a control technology to be considered 

feasible. 21As an example, in the 2010 SOx RECLAIM amendment, staff assessed 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 installed 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/heaters, based on information received 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 first installed in 1970, the fourth heater 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) 
Draft Final Staff Report – NOx RECLAIM 280 

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 survey 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 using 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 BARCT level of 2 ppmv NOx for FCCUs because only 

one FCCU is currently achieving this level. Staff is required to find technology that can potentially 

reduce maximum amount of pollution to meet the 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 technologies for FCCUs, SCRs as well as 

scrubber/LoTOx and estimated the cost-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 feasible 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 equipment such as LoTOx/scrubber and SCR can 

be designed to achieve the 2 ppmv level as confirmed 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 
Draft Final Staff Report – NOx RECLAIM 281 

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 range of $152 million (no markups) to $163 million (with 

two layers of markups used by NEC). NEC estimated $211 million (with different 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 staff’s estimates. The cost effectiveness 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 analysis should be changed because NEC estimated 

higher costs for certain equipment. 

Cost Effectiveness for Refinery Sector 

The costs and cost-effectiveness values for each individual class or category of sources are 

summarized in Table 6.1.6. The overall weighted average cost-effectiveness for the refinery sector 

based on NEC’s and staff’s estimates is $11 K per ton DCF ($18 K per ton LCF) with SCR 

technology, which is well below the thresholds that the commenter cited for the BACT Guidelines 

and the 2012 AQMP. 

Since RECLAIM achieves its reductions in the aggregate rather than based on individual 

equipment, it is appropriate to look 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 individual equipment from the BARCT analysis to be 

consistent with the SOx RECLAIM amendment in 2010. The cost-effectiveness values based on 

DCF and LCF methods are not directly 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 estimated compliance cost. Due to this methodological 

difference, staff disagrees with the commenter’s claim 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. 
Draft Final Staff Report – NOx RECLAIM 282 

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 2nd 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 case. The commenter however should cite the 

threshold for “incremental” cost effectiveness which looks at the difference in costs and emissions 

between a proposed BACT and a less stringent control level. The threshold for “incremental” cost 

effectiveness is $57,200 per ton as of 2nd quarter 2003 and should be adjusted to $80,000 per ton 

as of 2015 dollars. This is a more appropriate 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 Part C 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 facilities may be being treated 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 
Draft Final Staff Report – NOx RECLAIM 283 

October 6November December 4, 2015 

Table Z.1-9 Cost Effectiveness Comparison 

Cost Effectiveness ($/ton) 

Proposed Amendment 9,066 – 13,686

Control Measure CMB-01 7,950 (Phase 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-effectiveness for this proposed NOx RECLAIM amendment is 

less than the thresholds that the commenter cited 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 threshold of $22,500 proposed in the 2012 AQMP was 

intended as a threshold above which tiered levels of analysis would be conducted. It was not 

intended as a threshold above which a control 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 threshold of $50,000 per ton for “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 evaluation of site-specific factors for

each refinery, which staff did not appropriately consider. However, staff has maximized the use 

of site specific information provided by NEC on installation, design, engineering 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. 

As explained in response 1-6, in only one case did 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 gives 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 
Draft Final Staff Report – NOx RECLAIM 284 

October 6November December 4, 2015 

This commenter further asserts that staff did not properly consider 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 staff’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 RECLAIM 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 reductions 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, RECLAIM 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 the fourth largest source of NOx emissions in 

the Basin and the top #1 emitting stationary source. 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 BARCT 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 (miscellaneous NOx sources). The District has regulated sources as 

small as residential water heaters (Rule 1121). 
Draft Final Staff Report – NOx RECLAIM 285 

October 6November December 4, 2015 

Furthermore, the control technologies 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 disproportionate 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 equipment at the non-RECLAIM facilities are 

required to be discounted to the BACT level 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 or SOx 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 compliance 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 disproportionately impacted by participating in the program. 
Draft Final Staff Report – NOx RECLAIM 286 

October 6November December 4, 2015 

Response 1-12 Energy Efficiency 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 included in the baseline.) However, 

The RTC holdings (“Potential to Emit”) 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 compliance 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 amendment which would wash out the effect of the 

change in baseline year. 

26 Appendix L of the PDSR 

27 Appendix K of the PDSR 
Draft Final Staff Report – NOx RECLAIM 287 

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 consistent with the requirements in H&S Codes in evaluating and 

conducting a technical feasibility and cost-effectiveness 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, engineering 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 equipment 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 related 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 Account for 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. Staff 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 holdings if their actual emissions are lower than 

their PTE. 

Response 1-18 Compliance Margin 

Refer to Response 1-2 for discussion on compliance margin. The cement plant was shutting down 

but staff still included 0.29 tpd for the remaining 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 amount 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. 
Draft Final Staff Report – NOx RECLAIM 288 

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 than 0.1 tpd for ICEs and small boilers/heaters). 

Response 1-21 Implementation 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 Public Participation 

Staff has been conducted public meetings on the 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 Efficiency 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” Alternative (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 
Draft Final Staff Report – NOx RECLAIM 289 

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 addressing remaining emissions, Control Measure CMB01, shave methodology, and the necessity to seek for 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 response 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 not shown any need for the much longer amount 

of excess RTCs allowed by the industry’s proposal. 

Response 1-30 Remaining Emissions 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 equipment. 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 Appendix B – 2 ppmv Level for Boilers/Heaters 

Refer to Response 1-7. The count of boilers/heaters 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 ppmv should be considered as BARCT since it is 

“...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”.

Response 1-33 Appendix B – NEC’s Analysis for Boilers/Heaters 
Draft Final Staff Report – NOx RECLAIM 290 

October 6November December 4, 2015 

Refer to Response 1-7. Several heaters 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 RTC 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 “programmatic” 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 between NEC’s and staff’s estimates. Also, refer 

to Response 1-7. 

Response 1-35 Appendix D – Coke Calciner 

This comment supports staff recommended BARCT for this category. No response is needed. 

Response 1-36 Appendix E – SRU/TGs Applications 

NEC’s cost analysis does not alter the BARCT conclusion for SRU/TG applications. 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 Appendix K – Energy Efficiency Projects 

Refer to Response 1-12 

Response 1-38 Shave Approach 

Refer to Response 1-3. 
Draft Final Staff Report – NOx RECLAIM 291 

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% O2) NOx emissions is a justifiable emission level for 

SCR applications to FCCUs, Fired Heaters, Boilers, 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 for periods of 4 to 6 years) it is prudent and quite possibly necessary 

to design future SCRs to increase residence time, improve NH3 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 only 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 staff believes that 2 layers of catalysts are 

sufficient. The NEC model is not based on or proposed 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 aspects 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 allowable pressure drop, so superficial velocity is a good basis for 

comparison between units. The district has three operating FCCU SCRs. All units 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% O2.

The other unit, highlighted in the draft report, achieves less than 2 vppm @ 3% O2 operating at a 

superficial velocity of 7.7 ft/sec. The “good” unit is operating with inlet NOx levels which are 50% of
Draft Final Staff Report – NOx RECLAIM 292 

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 different costs and different 

overall performance impacts. NEC was not commissioned to do an evaluation of individual units and 

propose improvement options, but rather to make an assessment of what it would take, cost wise, to 

reliably achieve the 2 ppmv limit for grass roots SCR installations. Based on the experience of 

operating units in the district, and our direct experience 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/sec or less. Considering that SCR catalyst vendors have 

not developed and guaranteed a specific SCR design for 2 ppmvd @ 3% O2 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/proposals 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 “total 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 subsequent conversations 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 increase over 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 from Refineries 1, 5 and 6 is shown below. 
Draft Final Staff Report – NOx RECLAIM 293 

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) 95 - 97% 89% 83% 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 insufficient 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 in this table and the notes. It is also important 

to note that the PDSR did not include the NEC model (proposed to achieve a 2ppmv emissions 

limit) 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 application. 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 Table 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 cubic feet as estimated by NEC in Table 1 above. 
Draft Final Staff Report – NOx RECLAIM 294 

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 layers of catalysts would not affect the overall 

conclusion on the cost-effectiveness of the FCCU SCRs and would not impact the total proposed 

reduction in RTC holdings. 

Comment 2-4 NEC’s “Typical” FCCU SCR Design 

In their review, staff is suggesting that NEC’s typical SCR is overdesigned 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 in Comment 2-3) , NEC’s typical SCR should be able 

to achieve 97% NOx reduction by virtue of the addition of catalyst at higher gas velocities than the 

SCR operating at Refinery 1. The typical SCR design 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 NH3 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 your 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 3rd catalyst bed the change 

in overall cost-effectiveness would not impact the 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 catalysts 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 projects. These concepts were discussed with 

SCAQMD staff during reviews of our report and in subsequent follow-up phone conversations and 

e-mails. Due to the extensive discussion around this topic we are mystified by staff’s 

characterization of this “bid conditioning factor” as, and here I paraphrase, ‘an undefined and 

therefore invalid cost increase’. 
Draft Final Staff Report – NOx RECLAIM 295 

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, other 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 guarantee and without review of the specific codes and standards 

applicable to refinery installations. 

As project definition improves the process basis becomes fixed, equipment sizes become more 

reliable, performance guarantees are finalized, 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 difference seen between early equipment bids and final, 

full definition, performance guaranteed, 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 impact 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 definition 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 used in NEC’s cost work-up for all SCR projects 

(FCCU, Heaters/Boilers, etc.) is not an arbitrary factor 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, performance 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 in Appendix A with a 50% contingency 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 the SCR costs for Refinery 5, 6 and 7 based on 
Draft Final Staff Report – NOx RECLAIM 296 

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 manufacturers and since SCR 

is a mature technology, staff feels 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 conclusion 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 discussed with SCAQMD staff, and apparently dismissed as a simple adder to 

make costs appear high, is the cost of actually installing 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 the 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 cost to as much as 200% of direct equipment cost 

depending on the complexity of the equipment, the material it is made of and other equipment specific 

factors. In general, low cost equipment manufactured 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 distillation tower. Due to the simplicity of the SCR 

equipment and its use of low cost materials we have used an installation labor cost factor of 0.75 (75%) 

to account for physical installation of the SCR, structural steel, fit-up of ducting, 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, piping 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 concurs that the NEC approach which adds a 75% labor 

cost factor is a valid alternate assessment of the projected project costs. As previously mentioned 
Draft Final Staff Report – NOx RECLAIM 297 

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 PDSR 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 necessity. However, as shown in Table F.5, Appendix F, 

even if the 75% labor cost factor was included, 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 direct M&L costs (indirect costs, engineering and owner’s costs, labor 

productivity, ancillary equipment and systems, revamp items, duct work, area paving, lighting, 

utilities, safety systems, control system connections and programming, instrumentation, soot 

blowers, etc.) As a point of reference, the TIC factor 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-Confidential Report was posted for review, staff met with refinery 

personnel and their consultants who provided examples of SCR equipment purchases and 

installations at out-of-state refineries. 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 SCRs with 2 layers of catalysts). Staff 

reevaluated the EPA methodology in conjunction 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 NEC’s non-confidential report (14-045-4, November 

26, 2014). NEC back calculated expected FCCU rates from flue gas flow rate data provided by 

AQMD staff to obtain estimated FCCU sizes. The following 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 
Draft Final Staff Report – NOx RECLAIM 298 

October 6November December 4, 2015 

update to the cost of a Grass Roots SCR for Refinery 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 assumption 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 estimating 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 Refinery 1 which, according to Refinery 1 personnel, 

did not include the cost for waste heat boiler modifications. Subtracting this component from the 

TIC for a typical FCCU SCR installation and recalculating 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 based on data provided by refinery staff. Staff 

took the data reported by Refinery 1 as the total project cost for the SCR system including all 

peripheral equipment. 

Comment 2-10 

Staff also provided a review of NEC’s cost estimates based on staff’s assessment of differences 

between the data provided by an SCR vendor to staff and NEC for an installation at Refinery 9. 

In staff’s evaluation of the data provided by the vendor they incorrectly calculate the total catalyst 

volume to be 3,100 ft3 vs the actual vendor proposal which provided only 2,400 ft3

. Staff also 

incorrectly calculates NEC’s estimated catalyst volume at 12,697 ft3 vs an actual value of 4,600 
Draft Final Staff Report – NOx RECLAIM 299 

October 6November December 4, 2015 

ft3 (1.92 x vendor proposal, see previous discussion 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 represents the total SCR volume. As presented 

in the PDSR, the manufacturer’s recommendation for the Refinery 9 catalyst volume was 3,300 

ft3. A review of the data provided by the SCR manufactures will be conducted to conform to 

proposed specifications and correct any misrepresentations in the PDSR. 

Comment 2-11 

NEC provides a few comments on SCAQMD staff’s determination of PWVs for FCCU SCRs. 

1. In using the costs provided for Refinery 1’s SCR staff is assuming that all district SCRs can 

be installed without any impact on upstream equipment and that installation of the SCR can 

be executed in an open, non congested area. Refinery 1’s SCR was installed 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 scale more accurately when a figure of around 

0.6 is used. The effect of using a larger scale factor is a greater reduction in project costs for 

all projects with the differences getting proportionately 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 be made for the accuracy inherent in vendor’s 

budget quotations, which does not appear anywhere. 
Draft Final Staff Report – NOx RECLAIM 300 

October 6November December 4, 2015 

5. The PWVs provided for Refinery 7 and Refinery 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 ensure 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 with regards to our technical assessment of the 

FCCU costs. Staff notes areas of agreement and issues to be resolved. 

1. Refinery 1 provided staff with comprehensive cost data for its FCCU SCR. As such, we 

used this model to estimate PWV and associated 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 provide 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 layers of catalysts and no markups, the PWVs 

for Refinery 7 and 9 would be $20 million. Using the manufacturer’s cost data with 2 

layers of catalysts and two levels of markups as recommended by NEC, the PWVs for 

Refinery 7 and 9 would be $31 million. 
Draft Final Staff Report – NOx RECLAIM 301 

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% O2) NOx emissions is a justifiable emission 

level for SCR applications to FCCUs, Fired Heaters, Boilers, Gas Turbines and TGU/SRUs, with 

caveats. While a few existing units can meet this guideline under current operating conditions, many 

more, similarly designed units have not demonstrated similar low emissions capabilities. With the 

exception of Gas Turbine installations (which have an equivalent emission level of 6 ppmv @ 3% O2)

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% O2. In spite of the limited number of 

units (other than gas turbines) operating at or below 2 vppm NOx, we believe that it is possible to 

achieve these levels, but to guarantee long term reliable performance (refineries typically operate 24/7 

for periods of 4 to 6 years) it is prudent and quite possibly necessary to design future SCRs to increase 

residence time, improve NH3 distribution, improve overall flue gas flow distribution, add catalyst, etc. 

SCAQMD staff agrees with this concept but we have strong disagreement as to how much change from 

current SCR designs will be required to achieve the 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 creating 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 (within error bounds) when applied to specific Basin 

refinery SCR cases. They expressed that their cost curve better represented smaller heaters 

(<100mmbtu/hr heat release). 

Response to General Comments 

Staff 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 and application, staff’s analysis expanded beyond a 

solely SCR application to include control 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 firing rates less than 200 

mmbtu. The differences between the cost curves generated by the varying control equipment 

design assumptions lead to the uncertainty reflected in the number of boilers and heaters deemed 
Draft Final Staff Report – NOx RECLAIM 302 

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 dilution 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 control 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 FCCU SCR as the basis for its analysis for heater 

and boiler SCR. They cited uncertainty in vendor’s response 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 indicated 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 application 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 FCCU SCR 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 
Draft Final Staff Report – NOx RECLAIM 303 

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 use 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 slightly 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 
Draft Final Staff Report – NOx RECLAIM 304 

October 6November December 4, 2015 

NEC indicated that staff analysis was based on only one SCR achieving 1.6 ppmv. This SCR has 1 

layer of catalysts, however the heaters were fired at 65% capacity. NEC indicated that the vendor 

information provided by AQMD staff indicated that 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 layers. 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 velocity as recommended by the manufacturers. 

Response 3-4

Several prominent manufacturers indicated that one layer 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 boiler to sustain an operation between 3-year to 5-year 

turnaround period. The manufacturers indicated that even 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 system 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 data on 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 consistent 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. 
Draft Final Staff Report – NOx RECLAIM 305 

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 between 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. 
Draft Final Staff Report – NOx RECLAIM 306 

October 6November December 4, 2015 

Comment Letter #4 - RECLAIM Industry 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. The Coalition believes that the shave amount for the period 2016-

2017 should be no more than 2 tons per day, and that there 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 reduction or up to 4 tpd reduction should be removed 

from the market no later than 2016-2017. Staff disagrees that this proposal does not allow adequate 

time for implementation because there 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 equipment 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 Coalition 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 BARCT adjustment 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. 
Draft Final Staff Report – NOx RECLAIM 307 

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 Holding 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 large and runs the risk of repeating the program 

“meltdown” of 2000-2001 during the 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: 
Draft Final Staff Report – NOx RECLAIM 308 

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 enough 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 operation for shutdown facilities and new electric 

generating facilities. Staff may need to revisit 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 an artificially high target. Staff also creates a separate Regional 

NSR Holding Account to address the NSR holding 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 consistent 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 emergency is declared. Staff has 

accounted for increase electrification through the growth factor which assumes increased use of 

renewables. Note that ERCs of non-RECLAIM facilities 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 RTC price exceeds $15,00022,500 per ton), staff can 

convert the non-tradable/non-usable RTCs to tradable/usable RTCs upon the concurrence of the 

Governing Board. 

Comment 4-7 Energy efficiency projects 

The Coalition strongly opposes any effort to further 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 encouraged and the benefits of making those reductions 

retained by the facility operator making them. 

Response 4-7 
Draft Final Staff Report – NOx RECLAIM 309

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 efficiency 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. 
Draft Final Staff Report – NOx RECLAIM 310 

October 6November December 4, 2015 

Comment Letter #5 – Latham & 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 disadvantages entities that have made good faith 

trades after March 20. Two examples were provided 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 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 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 4th 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 4th 828 (2002)]. 
Draft Final Staff Report – NOx RECLAIM 311 

October 6November December 4, 2015 

Comment Letter #6 – Yorke Engineering, LLC., August 21, 2015 

Comment 6-1 New Emission Factors 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/mmscf to report NOx emissions. 

Response 6-1 

An August 19th 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 equipment indicates source tests 

may be required to verify lower emissions. We request that no source test shall be required for 

certified equipment. 

Response 6-2 

Source testing is the preferred method 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 control regulations. Based on feedback from 

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 6-3 RTU Reporting 

The current requirements are specified in 2012 Appendix A, Chapter 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 formatted. We have wasted 

hours of time working with this antiquated system which is still required by the regulation. We 

urgently request that the District update their electronic reporting system to allow more modern 

and easy to use technology. 

Response 6-3 

We agree that the electronic reporting system needs to be updated. This upgrade, however, would 

be very resource intensive for SCAQMD staff and the affected operators and is outside the scope 
Draft Final Staff Report – NOx RECLAIM 312 

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, 2015 

Comment 7-1 Electric Generating Facilities Need Quicker Access to Nontradable/Non-usable RTCs 

Response 7-1 

SCAQMD staff has taken your comments into consideration 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. The non-tradable/non-usable credits would also be 

accessed if the Governor of California declares a State of Emergency, but would be usable/non-
Draft Final Staff Report – NOx RECLAIM 313 

October 6November December 4, 2015 

tradable. Staff is not proposing a fee for access to the Regional NSR Holding Account due to 

comments received at Working Group and other meetings from many other electric generating 

facilities that a fee should not be imposed for using these credits. 

The commenter also expresses that the non-tradable/non-usable RTCs not be 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 such 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 portion would be available to meet NSR purposes for 

these facilities and also provide relief in the event of a power crisis. A regional hold account offers 

more flexibility than if each facility held the amount 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 
Draft Final Staff Report – NOx RECLAIM 314 

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 electricity 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 not have to be consecutive days so the total 

calendar days since the re-firing could be longer. 

The proposed amendment for requiring the disconnection 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 demonstrating non-operation such as stack 

emission monitoring and recordkeeping. 
Draft Final Staff Report – NOx RECLAIM 315 

October 6November December 4, 2015 

Comment 7-4 

Response 7-4 

The comment discusses the provisions regarding the 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 year 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 transactions. The commenter also pointed out a rule 

reference error in PAR 2002 (f)(1)(F). Staff has corrected the reference. 

Comment 7-5 
Draft Final Staff Report – NOx RECLAIM 316 

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 funded 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. The 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 electricity generation facilities can access 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 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. Combined with the lesser amount of RTCs available as 
Draft Final Staff Report – NOx RECLAIM 317 

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, staff 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 requirements 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 thereby 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 Emergency. 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. 
Draft Final Staff Report – NOx RECLAIM 318 

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 and useable credits may not be suitably responsive to 

our needs as municipal utilities. In other words, the Cities’ 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 credits can be realized in a faster timeframe for 

unforeseen situations where emergency power generation 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, which 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 credits (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-tradable 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 use 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. 
Draft Final Staff Report – NOx RECLAIM 319 

October 6November December 4, 2015 

Comment 8-3 

Sunset of Non-tradable/Non-usable Holdings. The Cities understand that SCAQMD proposes to 

discontinue the non-tradable/non-useable holdings in the year 2022. Given the uncertainty presented 

by increased integration of renewable resources and regional electrification, the Cities ask SCAQMD 

to provide for continued utilization of the non-tradable / non-useable holdings, at least for municipal 

utilities. 

Response 8-3

The comment requests that the non-tradable/non-usable holdings to be provided in perpetuity to 

municipal utilities. The staff proposal intends to submit the non-tradable portion of the shave into the 

SIP, and if they were held indefinitely and could potentially be accessed, they would never be available 

for SIP emission reductions. However, 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 impacts of potentially increased electricity demand and 

renewable penetration on NOX emissions, and will propose RECLAIM program adjustments to the 

Governing Board if needed. 

Comment 8-4 

Regional NSR Holding Account, Compatibility of Dual Purposes. The Cities appreciate that SCAQMD 

is proposing alternatives that would ease the NSR 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 clarify how the account can be available 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 accessed 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 using 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 exists today as RTCs can be 

sold after the compliance period ends. 
Draft Final Staff Report – NOx RECLAIM 320 

October 6November December 4, 2015 

Comment 8-5 

Additional entities or authorities should be allowed to declare the 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 official. Staff believes that a major power crisis would warrant this 

type of declaration and that local emergencies 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 could be made available. See Response 7-5. 

Comment 8-6 

It is unclear how access to RTCs would be granted or how competing 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 for easy access in case of an emergency. 

Response 8-6

The comment requests for further definition as to how the Regional NSR Account 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 short term crisis. If the crisis is prolonged such that the demand for 

emergency RTCs is greater than the supply, there will be time to return to the Governing Board to 

make program adjustments. The staff proposal includes 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 
Draft Final Staff Report – NOx RECLAIM 321 

October 6November December 4, 2015 

The Cities ask SCAQMD to clarify how the Regional NSR Holding 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 requirement. 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 Holding 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 the 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 offsetting annual emissions if a State of Emergency is 

declared. The non-tradable credit portion for newer facilities would not be available for sale, however. 
Draft Final Staff Report – NOx RECLAIM 322 

October 6November December 4, 2015 

Comment Letter # 9 – Eco Services 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 BARCT 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 the 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 that 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 small emitters. An equitable 

rule should provide the regulated community with a cost-effective means of complying. We 

request that the SCAQMD somehow provide a ceiling on the financial impact it will have on 

RECLAIM participants in terms of cost-effectiveness. BARCT sources will be subjected to costeffective controls. Similarly, the financial impact to non-BARCT sources should also be based on 

cost-effectiveness. 

It is our understanding that Non-Tradable/Non-Useable 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 considered to prevent non-compliance for non-BARCT 

sources if the NOx RECLAIM market fails such that 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 BARCT. Staff appreciates your comment and 

acknowledge all your efforts in reducing SOx emissions with the installation of the wet gas 

scrubber at your facility. We believe 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 installed. The implementation schedule is over several 

years, so the full magnitude of the shave would occur 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-month 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 report. The commenter also makes reference to a 
Draft Final Staff Report – NOx RECLAIM 323 

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 acknowledge that at the current price of credits of around 

$100 per pound, the cost of purchasing credits after the 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. 
Draft Final Staff Report – NOx RECLAIM 324 

October 6November December 4, 2015 

Comment Letter #10 – Charles Timms, Jr. Letter Dated September 17, 2015 

Comment 10 - 1 

Response 10-1
Draft Final Staff Report – NOx RECLAIM 325 

October 6November December 4, 2015 

The commenter has suggested that additional rule language be added to ensure that unused RTCs 

for 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, the non-tradable balance can be 

used for NSR holding purposes, and subsequently will become the portion that will fund the 

Regional NSR account for the same purpose. However, 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 Emergency, 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 designation 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 declared by the Governor. Staff 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. 
Draft Final Staff Report – NOx RECLAIM 326 

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 from yearly NSR holding requirements. 

Comment 11-2 
Draft Final Staff Report – NOx RECLAIM 327 

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 (in RECLAIM after October 15, 1993), would have access to a 

Regional NSR Holding Account to relieve them of NSR holdings requirements that often require 

holding excess credits at the potential to emit level, even though the actual emissions are far below 

this level. In addition, in the event of a power emergency, all electric generating facilities would 

have access to the Regional NSR account for credits used to offset these emissions during an 

emergency. 

Comment 11-3 

Response 11-3 

The comment states that access to additional credits should be realized in a faster timeframe for 

unforeseen situations where emergency power generation may be necessary. Non tradable/nonusable RTCs are proposed to be accessed immediately if a State of Emergency is declared. Please 
Draft Final Staff Report – NOx RECLAIM 328 

October 6November December 4, 2015 

refer to the response to Comment 11-2. Despite this, a facility would still have some time to 

reconcile all of its emissions 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 days do not have to be consecutive days so the 

total calendar days since the re-firing could be longer than 14 consecutive days. 
Draft Final Staff Report – NOx RECLAIM 329 

October 6November December 4, 2015 

Comment 11-5

Response 11-5

The comment expresses the support for the establishment of the Regional NSR Holding Account. 

We appreciate your support for these provisions affecting newer electric generating facilities with 

burdensome NSR holding requirements. 
Draft Final Staff Report – NOx RECLAIM 330 

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-owned subsidiary 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 purchased by IEEC, LLC. The GE RTC account is, and 

always has been, 100% dedicated to the IEEC. 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 RTC account be correctly categorized as an Electric 

Generating Facility (non-refinery) account in Table 8. Currently, GE is categorized as an 

“investor”. 

Response 12-1 

The comment requests for the Investor account that is associated with Inland Empire Energy 

Center 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 electric 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. Table 8 of Rule 2002 will also be updated to reflect 

this change. 
Draft Final Staff Report – NOx RECLAIM 331 

October 6November December 4, 2015 

Comment Letter #13

Comment 13-1 The Shave for the Program Should be a Minimum of 14.85 tpd 

We do not agree with the decision to reduce the total shave amount by 0.85 tpd, from the required 

14.85 tpd to 14 tpd. California’s Health & Safety Code is abundantly clear that trading programs 

must “result in an equivalent or greater reduction in emissions at equivalent 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 that 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” that 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. The reason that the overall RTC reduction is 14 tons 

per day and not more is to account for some BARCT uncertainties that arose in the refinery boiler 

and heater category. Staff and the consultant hired to do an independent BARCT assessment had 

some reasonable, but different engineering and cost assumptions which resulted in an adjustment 

to the staff proposal to account for this uncertainty. 

Comment 13-2 The Implementation 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 meeting 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 year reductions. In fact, we suggest 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 serves 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 for 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 complied with this provision for decades, and it makes 

sense to continue to place this duty on industry. 
Draft Final Staff Report – NOx RECLAIM 332 

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 generating facilities. The staff proposal aims to reduce the total allocation of

the RECLAIM universe by over 53%. This is a very substantial reduction, much more so than the 

22.5% reduction that resulted from the 2005 amendments to RECLAIM. Electrical Electricity 

generating facilities are in a unique situation in that 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 the actual emissions are far below this level. While 

the staff proposal will shave those electric generating facilities among the top 90% of RTC holders 

by 49%, the Regional Account would provide some relief from their NSR holding obligations and 

help to maintain a functioning market in the event 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 action. In particular, through the California Environmental Quality 

Act (“CEQA”) process, an assessment of a Command and Control alternative will be important to 

understand how quickly desperately needed reductions could be implemented in the South Coast 

under a regulatory program requiring implementation 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 achieve reductions sooner than this compliance 

schedule. 

Response 13-4 

The commenter requests that a command and control alternative should be evaluated by CEQA. 

The purpose of the RECLAIM program is to allow emission reductions equivalent or greater to 

command and control at an equivalent 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 control 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 priced are 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 section 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 
Draft Final Staff Report – NOx RECLAIM 333 

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 Approach Must Ensure Reductions from Refineries and 

Electric Generating Facilities.

The evidence presented by the District in this rulemaking indicates that refineries have used the 

NOx RECLAIM system as a shield from actually installing pollution control equipment like 

Selective Catalytic Reduction (“SCR”). Given this past behavior, we suggest that the best path 

forward is that refineries be taken out of the NOx RECLAIM program and be required to install 

pollution control equipment. 

Response 13-6 

The comment states that refineries should be removed from the RECLAIM program to force the 

installation of control equipment. As stated in the previous comment, the staff proposal is for a 

53% overall RTC reduction from the RECLAIM universe. 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. 
Draft Final Staff Report – NOx RECLAIM 334 

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 away 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 first 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 installed. 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 shave will be effective, several smaller projects 

would likely be installed, so when 2019 is reached, those larger projects that the commenter has 

referred to would be in place and would result in emissions under the allocation cap. 
Draft Final Staff Report – NOx RECLAIM 335 

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 accommodate Rule 219 boiler technology into the proposed 

RECLAIM amendments. After giving the concept more consideration, I continue to question the 

proposed requirement that such boilers be subject 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 that the benefits of certification (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 proposed 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 requirements of small, unpermitted 

boilers in the staff proposal for usage of a lower emission factor for reporting Rule 219 equipment 

emissions. See Response 6-2. 
Draft Final Staff Report – NOx RECLAIM 336 

October 6November December 4, 2015 

Comment Letter #16 George Piantka Email Dated August 14, 2015 

Comment 16-1 

In Rule 2005, will there be proposed language 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 was 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 demonstrate our continued holding and/or access to 

these RTC for the lenders. While not obvious, the financial implications are different 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 losing the unrealized value of IYB RTCs in a legacy 

RECLAIM account versus the purchase, shave and possible replacement of them 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 provisions that would provide some relief for the 

NSR holding requirements with the establishment of the Regional NSR Holding Account. 
Draft Final Staff Report – NOx RECLAIM 337 

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 audited with a full explanation of who is included or 

excluded and the reason for each. The NOx shave percentage adjusted for non-refinery RTC 

holders’ weighted reduction, currently 47%, would require adjustment if the list changes. 

Response 17-1 

The commenter requests for a clarification on which electric generating facilities are part of the 

proposal for the shave and if cogeneration facilities are to be considered electric generating 

facilities for inclusion in the shave. SCAQMD staff has taken your comments into consideration 

and acknowledges that all electric generating facilities were included into the shave, even those 

under the 90% RTC Holders cutoff so that those with NSR holding obligations would be able to 

use the Regional NSR Holding Account. Upon further consideration, staff has removed those 

electric generating facilities that are under the 90% cutoff for RTC holders from the list of facilities 

for the shave. 
Draft Final Staff Report – NOx RECLAIM 338 

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 available, and could face a potential increase in 

NOx emissions due to transportation electrification, the current rule language for the conversion 

of non-tradable/non-usable RTCs to non-tradable/usable is inequitable and costly. LADWP 

recommends an alternative approach applicable to electrical electricity generating facilities such 

that the non-tradable/non-usable RTCs continue to be deemed non-tradable, but usable for 

compliance without the price threshold trigger. 

Response 18-1 

SCAQMD staff has taken these comments into consideration 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 $22,500/ton. Those credits 

would become usable and tradable. The non-tradable/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 electricity 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 faster 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 renewable 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 program. 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 facilities 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 recommended 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 establishes the mechanism by which the non-tradable and 

Regional NSR accounts are handled. The non-tradable account is the yearly shaved amount of 
Draft Final Staff Report – NOx RECLAIM 339 

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 their non-tradable/non-usable RTCs in a State of 

Emergency, as well as the credits in the Regional 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 addition, 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 Account 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 feels 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 these RTCs could never be used for demonstrating 

attainment of the ozone or PM2.5 NAAQS, even though 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 purposes of compliance is constrained due to the 

State of Emergency declaration. The rule language suggests that the RTCs in this account are 

limited after NSR requirements 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 renewable production volatility. A 

“Reliability Coordinator” should have the authority to declare 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 be submitted to the State Implementation Plan. 

Response 18-3 

The comment expresses concerns on how the Regional NSR Holding account would function for 

electrical electricity 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-tradable/non-usable NOx RTCs may be used to offset 

emissions 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 there are not enough RTCs for all the power plants 

requesting relief, the RTCs will be distributed 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 
Draft Final Staff Report – NOx RECLAIM 340 

October 6November December 4, 2015 

would generate electricity during a State of Emergency. Given the quarterly 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 lesser 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, staff 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 the State of Emergency is prolonged, the proposed 

amendments 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. 

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 BARCT 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 are 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 distinction 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 that 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 draft 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 
Draft Final Staff Report – NOx RECLAIM 341 

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 for a postponement under this provision. Staff has 

revised the proposed rule to make this explicit. The commenter verbally expressed that this change 

satisfactorily addresses the concern regarding the length of time for conducting a RATA after the 

source is returned to service. 

Comment 18-6 

LADWP suggests that the semi-annual 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 first 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 opportunity available. Due to the unpredictability 

of electric demand, the schedule for operations is subject 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 attempting to comply with RATA requirements, but 

failed to due to circumstances beyond its reasonable control. Therefore, the exemption is only 

offered in these cases. It is unreasonable to allow delay in conducting RATA if 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 maintain operational fuel meters introduces 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 incorporated into the proposed amended rule that will be 

considered by the Governing Board. 

Comment 18-8 

LADWP presents a completely different alternative regulatory approach for consideration, which 

involves a credit mechanism by which electrical electricity generating facilities would have access 

to RTCs to support native load and transportation electrification. Two white papers are attached 

that detail this alternative approach and crediting mechanism, in addition to suggested resolution 

language addressing increased transportation electrification. 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 electrification measures. The tradable RTCs would not be 

adjusted, while the non-tradable RTCs would be adjusted to reflect the actual increased demand. 
Draft Final Staff Report – NOx RECLAIM 342 

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 emission reductions that would be achieved 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 approach, 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 the scope of this rule making for RECLAIM. As 

detailed in the previous responses to this comment 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 electrification 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 controls, 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 transportation sector today would be speculative. The staff proposal has 

provided additional safeguards, such as the threshold 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. 

.
Draft Final Staff Report – NOx RECLAIM 343 

October 6November December 4, 2015 

Comment Letter #19 Shell Energy North America (US), L.P. Letter Dated August 6, 2015 

Comment 19-1 

To meet the proposed amendments, the facility would 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 reduction 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 conditions in California, including the recent 

decommissioning of San Onofre Nuclear Generating Station. We request that SCAQMD consider 

that peaking generation facilities with lower capacity factor built to BACT should not be obligated 

under the proposed rule to make further emissions 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 question 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 requirements, 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 Holding 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 electricity 

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 expected that such facilities install further controls 

since most the equipment is already either at BARCT or BACT. The proposed rule has safeguards 

that can make non-tradable credits and Regional 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 allow 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 Amendment (the date that RTC holdings 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 established and does not address how NOx RTCs that were 

transferred between March 20, 2015 and the date of implementation of the Proposed Rule will be 
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October 6November December 4, 2015 

treated. We request that the SCAQMD act prospectively; the NOx RTC holdings should be the 

quantity as of the date of the implementation of the Proposed Rule. 

Response 19-2 

The commenter requests that the freeze date of the 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 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. Note that the March date was retained for determining which facilities were in the top 

90%, but the freeze date was changed due to stakeholder input. 

Comment 19-3 

Additional information and clarification 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.