South Coast Air Quality Management District 

Planning, Rule Development & Area Sources

Final Staff Report 

SOx RECLAIM

Part 1 

BARCT Assessment & 

RTC Reductions Analysis

November 2, 2010 

Deputy Executive Officer 

Elaine Chang, Dr PH 

Assistant Deputy Executive Officer 

Laki Tisopulos, Ph.D., P.E. 

Planning and Rules Manager 

Joe Cassmassi 

Author 

Minh Pham, M.S., P.E., Air Quality Specialist 

Contributor 

Kevin Orellana, Air Quality Specialist 

 

Reviewers 

Gary Quinn, P.E., Program Supervisor 

Joe Cassmassi, Planning & Rules Manager 

Laki Tisopulos, Ph.D., P.E., Assistant DEO 

William Wong, Principal Deputy District Counsel 

Note that on October 26, 2010, staff revised its proposal to 5.7 tons per day RTC reductions 

(51.4% shave) distributed in four phases in eight years from 2013-2019 and after. Since the 

actual emission reductions estimated pursuant to BARCT remain unchanged at 5.4 tons per 

day, there is no need to update this final staff report to include this minor change. 
 

Acknowledgements 

The author would like to thank the following AQMD’s staff members for providing information 

and participating in this project: 

Planning, Rule Development & Area Sources Division 

Susan Yan, Kathy Hsiao, Ali Ghasemi, Tuyet-Le Pham, Barbara Radlein, Steve Smith, Shah 

Dabirian, Sue Lieu, Tom Chico, Jillian Baker 

Engineering & Compliance Division 

Danny Luong, Mitch Haimov, Susan Tsai, Fortune Chen, Kyu Kyu Leung, Christian Hynes 

Tran Vo, Jay Chen & Refinery Team, Brian Yeh & his team 

Information Management Division 

George Haddad, Rezvan Ramezani 

Source Testing Division 

Mike Garibay & his team, Ramiro Gonzalez, Steve Marinoff 

Technology Advancement Office 

Marty Kay 
 

TABLE OF CONTENTS 

Table of Contents

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

CHAPTER 1 - BACKGROUND ............................................................................................................................. 19

1.1 LEGISLATIVE AUTHORITY............................................................................................................................ 19

1.2 FINE PARTICLE REGULATION AND SOX CONTROL....................................................................................... 19

1.3 CURRENT RECLAIM PROGRAM ................................................................................................................. 20

1.4 CONTROL MEASURE CMB-02 ..................................................................................................................... 21

1.5 AFFECTED FACILITIES .................................................................................................................................. 21

1.6 2007 AIR QUALITY MANAGEMENT PLAN ................................................................................................... 22

1.7 2005 ANNUAL EMISSIONS REPORT .............................................................................................................. 24

CHAPTER 2 – BEST AVAILABLE RETROFIT CONTROL TECHNOLOGY............................................... 26

2.1 DEFINITION .................................................................................................................................................. 26

2.2 BARCT EVALUATION PROCESS .................................................................................................................. 26

2.2.1 Identify Technology That Can Achieve Maximum Degree of Reduction ............................................. 26

2.2.2 Evaluate Control Effectiveness ........................................................................................................... 28

2.2.3 Conduct Top-Down Cost Effectiveness Analysis ................................................................................. 28

2.2.4 Select Best Available Retrofit Control Technology (BARCT) ............................................................. 29

CHAPTER 3 – FLUID CATALYTIC CRACKING UNITS ................................................................................. 31

3.1 PROCESS DESCRIPTION ................................................................................................................................ 31

3.2 CURRENT ALLOCATIONS AND EMISSIONS .................................................................................................... 32

3.2.1 Allocations .......................................................................................................................................... 32

3.2.2 Emissions ............................................................................................................................................ 33

3.3 CONTROL TECHNOLOGY .............................................................................................................................. 34

3.3.1 SOx Reducing Catalysts ...................................................................................................................... 34

3.3.2 Wet Gas Scrubbers .............................................................................................................................. 38

3.4 ACHIEVED-IN-PRACTICE INFORMATION ...................................................................................................... 43

3.5 PROPOSED BARCT LEVEL AND EMISSION REDUCTIONS ............................................................................. 45

CHAPTER 4 – REFINERY BOILERS AND HEATERS ..................................................................................... 47

4.1 PROCESS DESCRIPTION ................................................................................................................................ 47

4.2 CURRENT ALLOCATIONS AND EMISSIONS .................................................................................................... 48

4.2.1 Allocations .......................................................................................................................................... 48

4.2.2 Emissions ............................................................................................................................................ 48

4.3 CONTROL TECHNOLOGY .............................................................................................................................. 49

4.3.1 Lower Sulfur Fuels .............................................................................................................................. 49

4.3.2 Improving Efficiency of Fuel Gas Treating System ............................................................................. 50

4.3.3 Flue Gas Scrubbers ............................................................................................................................. 51

4.4 PROPOSED BARCT LEVEL AND EMISSION REDUCTIONS ............................................................................. 53

CHAPTER 5 – SULFUR RECOVERY – TAIL GAS UNITS .............................................................................. 54

5.1 PROCESS DESCRIPTION ................................................................................................................................ 54

5.2 CURRENT ALLOCATIONS AND EMISSIONS .................................................................................................... 56

5.2.1 Allocations .......................................................................................................................................... 56

5.2.2 Emissions ............................................................................................................................................ 57

5.3 CONTROL TECHNOLOGY .............................................................................................................................. 58

5.3.1 Increase Efficiency of the Sulfur Recovery Unit ................................................................................. 58

5.3.2 Increase Efficiency of Tail Gas Unit ................................................................................................... 59

5.3.3 Wet Gas Scrubber ............................................................................................................................... 61

5.4 PERFORMANCE INFORMATION ..................................................................................................................... 64

5.5 BARCT LEVEL AND EMISSION REDUCTIONS .............................................................................................. 66
 

CHAPTER 6 – SULFURIC ACID MANUFACTURING ..................................................................................... 67

6.1 PROCESS DESCRIPTION ................................................................................................................................ 67

6.2 CURRENT ALLOCATIONS AND EMISSIONS .................................................................................................... 68

6.2.1 Allocations .......................................................................................................................................... 68

6.2.2 Emissions ............................................................................................................................................ 68

6.3 CONTROL TECHNOLOGY .............................................................................................................................. 69

6.3.1 EPA BARCT Clearinghouse ................................................................................................................ 69

6.3.2 Clean Air Act Settlements .................................................................................................................... 69

6.4 PROPOSED BARCT LEVEL AND EMISSION REDUCTIONS ............................................................................. 71

CHAPTER 7 – CONTAINER GLASS MELTING FURNACES ......................................................................... 73

7.1 PROCESS DESCRIPTION ................................................................................................................................ 73

7.2 CURRENT ALLOCATIONS AND EMISSIONS .................................................................................................... 74

7.2.1 Allocations .......................................................................................................................................... 74

7.2.2 Emissions ............................................................................................................................................ 74

7.3 CONTROL TECHNOLOGY .............................................................................................................................. 75

7.4 BARCT LEVEL AND EMISSION REDUCTIONS .............................................................................................. 76

CHAPTER 8 – COKE CALCINING ...................................................................................................................... 78

8.1 PROCESS DESCRIPTION ................................................................................................................................ 78

8.2 CURRENT ALLOCATIONS AND EMISSIONS .................................................................................................... 79

8.2.1 Allocations .......................................................................................................................................... 79

8.2.2 Emissions ............................................................................................................................................ 79

8.3 CONTROL TECHNOLOGY .............................................................................................................................. 80

8.3.1 Dry Scrubber at BP Wilmington ......................................................................................................... 80

8.3.2 Wet Scrubber and Wet ESP at BP Cherry Point Refinery ................................................................... 81

8.4 BARCT LEVEL AND EMISSION REDUCTIONS .............................................................................................. 82

CHAPTER 9 – PORTLAND CEMENT MANUFACTURING ............................................................................ 84

9.1 PROCESS DESCRIPTION ................................................................................................................................ 84

9.2 CURRENT ALLOCATIONS AND EMISSIONS .................................................................................................... 86

9.2.1 Allocations .......................................................................................................................................... 86

9.2.2 Emissions ............................................................................................................................................ 86

9.3 CONTROL TECHNOLOGY FOR COAL-FIRED FLUIDIZED-BED BOILERS ......................................................... 87

9.3.1 In-Process Control Technology .......................................................................................................... 87

9.3.2 Dry and Wet Scrubber ......................................................................................................................... 88

9.3.3 Costs and Cost Effectiveness Reported in Literature .......................................................................... 88

9.4 CONTROL TECHNOLOGY FOR CEMENT KILNS .............................................................................................. 89

9.4.1 Fuel Switching..................................................................................................................................... 89

9.4.2 Process Control................................................................................................................................... 89

9.4.3 Lime or Limestone Spray Dryer Absorber .......................................................................................... 90

9.4.4 Wet Scrubber ....................................................................................................................................... 90

9.4.5 Costs and Cost Effectiveness ..................................................................................................................... 90

9.5 BARCT LEVEL AND EMISSION REDUCTIONS .............................................................................................. 91

CHAPTER 10 – CONTINUOUS EMISSIONS MONITORING SYSTEM ........................................................ 93

10.1 DILUTION-EXTRACTIVE ............................................................................................................................... 93

10.2 EXTRACTIVE NON-DILUTION ....................................................................................................................... 94

CHAPTER 11 – WATER & WASTEWATER ...................................................................................................... 97

11.1 DISTRICT’S SURVEY .................................................................................................................................... 97

11.1.1 Water Demand ....................................................................................................................................... 97

11.1.2 Wastewater ............................................................................................................................................. 98

11.2 CALIFORNIA WATER PLAN ........................................................................................................................ 105

11.3 20X2020 WATER CONSERVATION PLAN .................................................................................................... 108

11.4 URBAN WATER MANAGEMENT PLANS .......................................................................................................... 113

11.5 CONCLUSION ............................................................................................................................................. 121

CHAPTER 12 – COSTS & COST EFFECTIVENESS ANALYSIS .................................................................. 123
 

12.1 SCENARIO ANALYSIS ................................................................................................................................. 123

12.2 COST-EFFECTIVENESS ANALYSIS USING NEC’S ESTIMATES ..................................................................... 130

12.3 COMPARISON OF COSTS AND COST-EFFECTIVENESS.................................................................................. 133

12.4 COST EFFECTIVENESS FOR SCENARIO 4 AND SCENARIO 5 ......................................................................... 134

12.5 INCREMENTAL COST EFFECTIVENESS ........................................................................................................ 136

12.6 COMPARISON OF COST EFFECTIVENESS TO OTHER RULES ADOPTED BY THE GOVERNING BOARD ............ 136

CHAPTER 13 – RTC REDUCTIONS & IMPLEMENTATION ....................................................................... 138

13.1 RTC REDUCTIONS ESTIMATED FROM 1997 BASELINE ............................................................................... 138

13.2 ALTERNATIVE SHAVE ................................................................................................................................ 141

13.3 RTC REDUCTIONS ESTIMATED FROM 2005 BASELINE ............................................................................... 141

CHAPTER 14 – COMMENTS & RESPONSES .................................................................................................. 145

RESPONSES TO WSPA’S COMMENTS RECEIVED IN REFINERY COMMITTEE MEETING ON OCTOBER 14, 2010 ....... 145

RESPONSES TO INTERCAT’S COMMENTS RECEIVED ON OCTOBER 10, 2010 ....................................................... 147

RESPONSES TO OWENS-BROCKWAY’S COMMENTS RECEIVED ON OCTOBER 21, 2010 ........................................... 153

RESPONSES TO OWENS-BROCKWAY’S COMMENTS RECEIVED ON SEPTEMBER 22, 2010 ....................................... 157

RESPONSES TO WSPA’S COMMENTS RECEIVED FROM MARCH 2010 TO AUGUST 2010 ........................................ 178

RESPONSES TO WSPA’S COMMENTS RECEIVED ON JULY 14, 2009 ....................................................................... 187

RESPONSES TO CHEVRON’S COMMENTS RECEIVED ON JULY 14, 2009 .................................................................. 201

RESPONSES TO TESORO’S COMMENTS RECEIVED ON JULY 14, 2009 ..................................................................... 205

RESPONSES TO BP’S COMMENTS RECEIVED ON JULY 14, 2009 ............................................................................. 208

RESPONSES TO PARAMOUNT’S COMMENTS RECEIVED ON JULY 14, 2009 .............................................................. 208

RESPONSES TO WSPA’S COMMENTS RECEIVED ON JULY 2, 2008 ......................................................................... 210

RESPONSES TO BP’S COMMENTS RECEIVED JULY 1ST, 2008 .................................................................................. 214

RESPONSES TO VALERO’S COMMENTS RECEIVED JULY 1ST, 2008 .......................................................................... 218

RESPONSES TO RHODIA’S COMMENTS RECEIVED APRIL 29TH, 2008 ...................................................................... 220

RESPONSES TO RHODIA’S COMMENTS RECEIVED NOVEMBER 25TH, 2008 ............................................................ 220

RESPONSES TO WSPA’S COMMENTS RECEIVED APRIL 29TH, 2008 ........................................................................ 223

REFERENCES ........................................................................................................................................................ 237

APPENDIX A – EMISSIONS, RTC HOLDINGS, AND INITIAL ALLOCATIONS ...................................... 240

APPENDIX B – SUMMARY OF FEDERAL, STATE AND LOCAL SOX RULE REQUIREMENTS ........ 246

APPENDIX C – CEMS INFORMATION & SOURCE TEST DATA ............................................................... 249

APPENDIX D – SURVEY QUESTIONNAIRES ................................................................................................. 252

APPENDIX E – ANALYSIS FOR RULE 1105.1 COSTS. .................................................................................. 258

APPENDIX F – U.S. REFINERIES OPERABLE CAPACITIES ...................................................................... 267

APPENDIX G – FCCU CAPACITY OF CALIFORNIA REFINERIES .......................................................... 271

APPENDIX H – LIST OF WORLD’S LARGEST CORPORATIONS ............................................................. 272

APPENDIX I – PROJECTED 2019 EMISSIONS & GROWTH FACTORS ................................................... 273

APPENDIX J – SOCIOECONOMIC ANALYSIS .............................................................................................. 275
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 1 November 2, 2010 

Executive Summary 

RECLAIM Program & Best Available Retrofit Control Technology 

On October 15, 1993, the District’s Governing Board adopted Regulation XX - Regional Clean 

Air Incentives Market (RECLAIM) and established a declining cap and trade mechanism to 

reduce NOx and SOx emissions from the largest stationary sources in the South Coast Air Basin 

(Basin). Regulation XX is comprised of 11 rules that specify the rules applicability, NOx and 

SOx facility allocations, general requirements, as well as monitoring, reporting, and 

recordkeeping requirements for NOx and SOx sources located at RECLAIM facilities. The 

RECLAIM program started with 41 SOx facilities and 392 NOx facilities. By the end of 2005 

compliance year, the program included 33 SOx facilities and 304 NOx facilities. By the end of 

2008, the SOx facilities reduced to 32 facilities. 

Under the SOx RECLAIM program, the RECLAIM facilities are issued SOx annual allocations 

(also known as facility caps), which decline annually from 1993 until 2003 and remain constant 

after 2003. The annual allocations issued to the RECLAIM facilities reflect the levels of Best 

Available Retrofit Control Technology (BARCT) envisioned to be in place at the RECLAIM 

facilities, and were the results of a BARCT analysis in 15 years, conducted in 1993. Since 

1993, the District conducted one BARCT reassessment for NOx in 2005, and has not yet 

conducted a BARCT reassessment for SOx. Under the RECLAIM program, the facilities have 

the flexibility to install air pollution control equipment, change method of operations, or 

purchase RECLAIM Trading Credits (RTCs) to meet the BARCT levels. 

AQMD staff is proposing amendments to Regulation XX – RECLAIM to achieve additional 

SOx reductions pursuant to the 2007 AQMP Control Measure CMB-02. The proposed 

amendments address requirements for BARCT in accordance with California Health and Safety 

(H&S) Code §40440, which is applicable to market-based incentive programs, as well as 

equivalency to command-and-control regulations, as required under H&S Code § 39616(c)(1). 

Reductions in SOx will help the Basin attain the federal annual average PM2.5 standard by 

2015, and the federal 24-hour average standard by 2020. Other proposed rule amendments 

include clarifications and changes to the protocols. 

PM2.5 Implementation Rule 

In March 2007, the U.S. Environmental Protection Agency (EPA) issued a final rule, known as 

the Clean Air Fine Particle Implementation Rule, which requires non-attainment areas such as 

the South Coast Air Basin to meet the fine particulate (PM2.5) standards by 2010. The Clean Air 

Fine Particle Implementation Rule requires the District to achieve the fine particulate standards 

as expeditiously as possible, and allows the District a one-time extension up to five years but no 

later than 2015. The rule requires the District to evaluate and employ all control measures to 

reduce the direct PM2.5 emissions, as well as the emissions from PM2.5 precursors, specifically 

sulfur dioxide (SO2), and the most potent PM2.5 precursors. 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 2 November 2, 2010 

2007 Control Measure CMB-02 - Further SOx Reduction for RECLAIM (SOx) 

To establish the basis for future compliance with the final U.S. EPA rule, staff has developed 

the 2007 Air Quality Management Plan (AQMP) Control Measure CMB-02 – Further SOx 

Reduction for RECLAIM (SOx) adopted by the Governing Board in July 2007. This control 

measure proposed to further reduce SOx allocations by approximately 3 tons per day in 2011-

2014 to help the basin achieve the PM2.5 standards by 2014 and also stated that staff may need 

to incorporate the concept of facility modernization as described under Control Measure MCS01 - Facility Modernization to achieve additional reductions beyond 2014 to meet the 2020 24-

hour standard. 

RTC Holdings, 2005 Emissions Distribution & BARCT Area of Focus 

In 1993, the District issued a total of 12 tons per day of SOx allocations for the 2003 

compliance year and beyond for the facilities in SOx RECLAIM. This is also the 2002 baseline 

for RECLAIM facilities used in the 2007 Air Quality Management Plan. It should be noted that 

the SOx RECLAIM emissions and RTC market are not distributed uniformly: In 2005, the SOx 

RECLAIM facilities emitted a total of 10.04 tons per day emissions.; more than 92% of the 

emissions was generated by the top 11 facilities; and in these 11 facilities, the top 7 source 

categories listed below were responsible for 80% of the facility emissions. 

⎯ Fluid catalytic cracking units; 

⎯ Sulfur recovery and tail gas treatment units; 

⎯ Boilers and heaters using refinery gas; 

⎯ Sulfuric acid manufacturing plants; 

⎯ Container glass melting furnace; 

⎯ Coke calciner; 

⎯ Cement kilns and a coal steam boiler at a cement manufacturing facility. 

These top emitters emitted approximately 7.53 tons per day in 2005 and are the focus for 

BARCT evaluations in this proposed rule amendment. The remaining facilities either do not 

have any equipment subject to proposed new BARCT, or their facility emissions are too low to 

make BARCT cost-effective. Figure EX-1 presents the 2005 emissions distribution, and Figure 

EX-2 presents a comparison for RTC Holdings and emissions between the top 11 facilities and 

the remaining 21 active facilities in SOx RECLAIM universe. 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 3 November 2, 2010 

FIGURE EX-1 

2005 Emissions Distribution 

FCCUs

3.55tpd

Boilers/Heaters

2.57 tpd

SRU/TG

1.03 tpd

Calciner

0.35 tpd Sulfuric Acid

1.16 tpd

Glass

0.32 tpd Cement

0.27 tpd

Others

0.79 tpd

Total 32 active facilities = 10.04 tons per day audited emissions.  

Top 11 facilities.  Top 7 sources.

FIGURE EX-2 

Distributions of RTC Holdings versus 2005 Emissions 

1

RTC HOLDINGS (TPD) 2005 EMISSIONS (TPD)

10.21

9.31

0.83

11 Major Facilities

21 Other Facilities

Investors

0.73 0.73

 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 4 November 2, 2010 

Public Process 

The public process of the PAR XX is summarized in Table EX-1. In 2008, staff formed the 

RECLAIM Working Group that included members representing SOx RECLAIM facilities, the 

Western States Petroleum Association (WSPA), the environmental community, as well as 

CARB and U.S. EPA to discuss and brainstorm the proposed amended SOx RECLAIM. The 

first meeting was conducted on February 7, 2008. 

On April 3, 2008, staff released the first Preliminary Draft Staff Report, and conducted two 

Working Group meetings on April 3 and April 30, 2008 to discuss staff’s initial proposal 

including allocations, emissions inventory and distribution, and potential BARCT for seven (7) 

major emitting categories of stationary source equipment located at the eleven (11) major SOx 

RECLAIM facilities. 

In May 2008, staff, WSPA and the refineries worked in collaboration to develop a Request for 

Proposal (RFP) to solicit expert consultants to conduct independent studies on feasibility and 

cost effectiveness. Additional working group meetings were held on May 15, May 28, and July 

2 to discuss the Request for Proposal. On July 11, 2008, the Governing Board approved the 

release of the RFP and staff conducted a Bidder’s Conference immediately after. A public 

notice advertising the RFP and inviting bids was published in accordance with AQMD’s 

Procurement Policy and Procedure. The District’s procurement office received and accepted a 

total of six (6) proposals. 

Staff formed an evaluation panel in August 2008 to evaluate the potential contractors. The four 

member evaluation panel consisted of one AQMD Assistant Deputy Executive Officer from 

Planning, Rule Development, and Area Sources Division; one AQMD Program Supervisor of 

the Best Available Control Technology team; one AQMD Program Supervisor of the Refinery 

Team; and one representative from WSPA. Staff invited one representative from the 

environmental group and two representatives from the U.S. EPA; however, they could not 

participate in this evaluation process due to schedule conflicts. 

The panel was in agreement that the contractors possessed good qualifications, presented good 

approaches and had workable schedules. After serious consideration, the panel recommended 

the Governing Board award the contracts to: 

⎯ ETS, Inc. in the amount not to exceed $289,360 to conduct analyses for refinery Fluid 

Catalytic Cracking Units (FCCUs), boilers/heaters, and sulfur recovery units and tail gas 

treatment units (SRU/TGTUs); and 

⎯ NEXIDEA Inc. in the amount not to exceed $45,500 to conduct analyses for sulfuric 

acid manufacturing facility and a coke calciner facility. 

The panel recommendation was approved by the Governing Board in a public meeting on 

September 5, 2008. The two consulting firms started the projects immediately after receiving the 

awards. First, the consultants and staff scheduled and conducted site visits at BP, Chevron, 

ConocoPhillips, Tesoro, Valero, ExxonMobil, California Portland Cement, Owens Brockway, 

and Rhodia in September and October 2008. During these site visits, the consultants gathered all 

necessary technical information on equipment and operating conditions, discussed operational 

characteristics of the equipment with the facilities, observed the physical layout of the 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 5 November 2, 2010 

equipment, as well as listened to any concerns or foreseen constraints provided by the refinery 

technical experts related to future prospective add-on control devices. 

After the site visits, the consultants conducted their own independent research, contacted the 

control manufacturers and vendors, gathered cost information, and performed their own 

independent engineering analyses on commercially available control technologies and cost 

effectiveness. In October 2008, the consultants developed the draft reports which were 

distributed to the affected facilities and AQMD staff for comments. After addressing all 

comments received from the facilities, as well as AQMD staff, the consultants finalized their 

analyses and reports for coke calciner, cement kilns, coal fired boiler, glass furnaces, and sulfuric 

acid plants on December 16, 2008 as planned in the contracts. 

Because of the complexity associated with the refinery systems, the analyses related to FCCUs, 

SRU/tail gas, and fuel gas treatment could not be completed in December 2008. The contractors 

and staff scheduled another round of extensive site visits at all six refineries in January and 

February 2009. The consultants’ draft analyses were provided to the refineries a total of four 

times (October 2008, January, February and March 2009) for comments. The primary 

consultant, ETS, Inc., and the subcontractor, AEC Engineering, addressed substantial amount of 

comments received from all six refineries, revised their reports appropriately, and finalized their 

assessment for the refineries in April 2009. The non-confidential reports from NEXIDEA, ETS 

and AEC Engineering are available for public information. 

In 2009, staff reconvened the Working Group meetings. A Public Workshop was conducted on 

June 23, 2009, and in this workshop, staff released 1) the Draft Staff Report to discuss BARCT, 

cost effectiveness, RTC reduction methodology, and timing of the proposed rule 

implementation; 2) Notice of Preparation of the Draft Environmental Assessment; and 3) the 

Draft PAR XX. In addition, staff conducted numerous meetings with WSPA and WSPA 

members, and other affected facilities as requested. Two Working Group meetings were held 

on August 27 and December 15, 2009. 

At the January 8, 2010 Governing Board Meeting, staff conducted an Informational Hearing to 

inform the Governing Board and the public about the development of PAR XX, the main issues 

associated with the proposed amended rule, and proposed a Work Plan for 2010 which was 

developed in collaboration with WSPA and provided a roadmap towards resolving pending 

issues. To address concerns by WSPA relative to the feasibility and cost analyses conducted by 

ETS/AEC and NEXIDEA in 2008-2009, the Governing Board approved in January 2010 the 

hiring of a second consultant to provide an independent review of the analyses previously 

conducted. To fulfill that commitment, staff hired Norton Engineering Inc. (NEC) to review 

ETS, Inc. and NEXIDEA’s feasibility and costs analyses. NEC was the next highest ranked 

consultants from the six initially reviewed, and the highest ranked by WSPA. NEC and staff 

visited the refineries in March/April, and NEC completed its review and issued a final report on 

June 15. Between April to June, staff met with WSPA and the refineries numerous times to 

discuss RTC shave methodologies, costs, and estimate impacts to the refineries. 

On August 18, 2010, staff released its Draft CEQA document concurrently with the second 

Refinery Committee Meeting addressing SOx RECLAIM. Staff also conducted a Public 

Working Group Meeting and a Public Consultation Meeting on September 8, 2010. Staff’s 

revised estimates for BARCT reductions at this time were 5.4 tpd emission reductions from 

2005 baseline, 6.1 tpd RTC reductions from 2012 – 2019 amounting to a 55% RTC shave. The 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 6 November 2, 2010 

estimated total costs are $630 - $745 millions, and cost effectiveness of about $16 K - $19 K per 

ton SOx reduced. 

In staff’s current proposal, several significant changes have been made as follows: 1) exclusion 

of emission reductions of 0.85 tpd estimated from boilers/heaters since the proposed BARCT 

limit was unchanged from the previous BARCT level of 40 ppmv; 2) use of audited emissions 

in the analysis for RTC shave, and 3) extension of the compliance period to 2019 instead of 

2017 as previously proposed, and 4) accounting for growth in emissions as was done in the 

2005 BARCT reassessment under NOx RECLAIM. 

The proposed amendments to SOx RECLAIM have been scheduled to be presented to the 

Governing Board for consideration at the November 5, 2010 Governing Board Meeting. 

TABLE EX-1 

Summary of the rule development process for Proposed Amended Regulation XX 

Calendar Year 2008 

January 02, 2008 RECLAIM Working Group was formed 

February 07, 2008 Public Consultation Meeting was conducted 

April 03, 2008 

April 30, 2008 

Preliminary Draft Staff Report was released. Two Working Group 

Meetings were conducted. 

May 1, May 15, 

May 28, June 20, 

July 02, 2008 

Request for Proposal to seek expert consultants was drafted and 

discussed with the RECLAIM Working Groups on three Working 

Group Meetings from May to July. A Stationary Committee 

Meeting was also conducted on June 20. 

July 11, 2008 

July 16, 2008 

RFP was presented to the Governing Board, and received 

Governing Board’s approval to release on July 11. A Bidder 

Conference was conducted on July 16 

August 1, 2008 

August 30, 2008 

Staff formed a task force to evaluate the six proposals received & 

make recommendation to the Governing Board 

September 5, 2008 Staff presented the recommendation of consultants to the 

Governing Board and received an approval to hire ETS, Inc. and 

NEXIDEA 

September 15, 2008 

October 15, 2008 

The consultants visited the facilities and conducted their feasibility 

and cost analyses, and the draft analyses were released to the 

facilities for comments. 

December 16, 2008 NEXIDEA finalized the analyses for coke calciner and sulfuric acid 

plants. ETS Inc. finalized the analyses for glass and cement 

facilities. 

Calendar Year 2009

January – 

April 20, 2009 

ETS Inc., their subcontractors, and staff conducted a second visit to 

all refineries. ETS, Inc. released their draft analyses three 

additional times to the refineries for comments and finalized their 

analyses on April 20, 2009. 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 7 November 2, 2010 

TABLE EX-1 (Cont.) 

June 23, 2009 

(Public Workshop and 

CEQA Scoping 

Meeting) 

Staff conducted a Public Workshop and CEQA Scoping Meeting. 

At this stage, staff proposed about 7 tpd RTC reduction from 2012-

2017 with a total costs (present worth value for 25 years) estimated 

to be $883 - $944 million dollars and a weighted average cost 

effectiveness of about $16 K per ton SOx reduced. Staff released 

the draft staff report, Notice of Preparation for Environmental 

Assessment, and draft rule. 

June 19, 2009 

November 20, 2009 

Two Stationary Committee Meetings were conducted in 2009. In 

addition, from March – December, staff conducted several 

meetings with WSPA and the refineries to discuss issues related to 

costs, baseline and RTC shave methodologies. 

December 11, 2009 

December 15, 2009 

The Governing Board established a Refinery Committee Group and 

conducted the first Refinery Committee Meeting on December 11 

and a WGM on December 15. At this stage, staff’s estimates were 

6.2 tpd emission reductions from 2005 baseline, 7.5 tpd RTC 

reduction, 64% - 67.5% RTC shave, total estimated costs of $745 

million, and cost effectiveness of about $13 K per ton SOx reduced. 

Calendar Year 2010

January 08, 2010 

(Informational 

Hearing) 

Staff conducted an “Informaltional Hearing” to inform the 

Governing Board and the public about the development of PAR 

XX, the main issues associated with PAR XX, and a proposed 

Work Plan for 2010. 

March 10, 2010 – 

June 15, 2010 

As called for under the Work Plan and approved by the Governing 

Board, staff hired a Norton Engineering Inc. (NEC) to review ETS, 

Inc. and NEXIDEA’s feasibility and costs analyses. NEC and staff 

visited the refineries in March/April, and NEC completed its 

review and issued a final report on June 15. In April – June, staff 

also met with WSPA and the refineries numerous times to discuss 

RTC shave methodologies and costs, costs and cost-effectiveness 

analyses. In addition, staff contacted the California Department of 

Water Resources and other water purveyors to discuss about the 

water impacts of the proposal, current and potential future 

regulations related to water usage in California. 

August 18, 2010 Draft CEQA document was released and staff conducted a second 

Refinery Committee Meeting. Staff’s revised estimates were 5.4 

tpd emission reductions from 2005 baseline, 6.1 tpd RTC reduction 

from 2012 - 2019, 55% RTC shave, total estimated costs of $630 - 

745 million, and cost effectiveness of about $16 K - $19 K/ton. 

Staff excluded the emission reductions of 0.85 tpd estimated from 

boilers/heaters, used audited emissions in the analysis for RTC 

shave, extended the compliance period to 2019 and accounted for 

growth. 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 8 November 2, 2010 

TABLE EX-1 (Cont.) 

September 8, 22, and 

24, 2010 

Staff reconvened the WGM & conducted a Public Consultation 

Meeting on September 8, a RCM on September 22, and a SSC 

Meeting on September 24, 2010. 

October 1, 2010 

October 14, 2010 

Set Hearing for PAR XX was conducted on October 1st, 2010- 

Revised Draft Staff Report and Socioeconomic Analysis were 

released for 30-day public review. RCM was conducted on 

October 14. On October 26, staff revised its proposal to 5.7 tpd 

RTC reduction (51.4% shave) in 4 phases: 3 tpd in CY 2013, 4 tpd 

in CY 2014, 5 tpd in CY 2017, and 5.7 tpd in CY 2019. 

November 5, 2010 A Governing Board Hearing is planned for November 5, 2010. 

Current Staff Proposal for BARCT and SOx RTC Reductions

To estimate SOx RTC reductions, staff used the RTC reduction methodology first developed in 

the 2005 NOx RECLAIM rule amendment. In this methodology, the base year inventory (i.e., 

1997) was selected. Associated growth factors were used to project the 1997 audited emissions 

to year 2019. BARCT adjustment was then applied to the projected 2019 inventory to calculate 

the remaining emissions at BARCT levels. Staff then applied a 10% adjustment (increase) to 

the remaining emissions to account for inaccessible RTCs due to imperfect market conditions 

and RTCs held by facilities to ensure compliance with annual audits. The proposed project 

results in 5.4 tons per day emission reductions from the 2005 baseline. This is equivalent to 6.1 

tons per day RTC reduction, approximately 55% reductions of RTC’s holdings of 11.09 tons per 

day by 2019.1

 

In staff’s current proposal shown in Table EX-2, staff made the following changes: 

• Staff removed emission reductions estimated for boilers/heaters. Since the proposed 

BARCT limit is retained at 40 ppmv for boilers/heaters, any reductions estimated for 

boilers/heaters from the 2005 baseline are considered as “opportunity reductions” that the 

facilities may select to implement, but not as reductions due to new BARCT. 

• Staff used 1997 audited emissions instead of reported emissions to estimate RTC shave, 

• Staff provided additional 2 years for implementing the RTC reductions as requested by 

several RECLAIM facilities, and extended the implementation period to 2019 and 

incorporated growth factor adjustments to reflect the extension period. 

 

1 Based on RTC records as of August 29, 2009 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 9 November 2, 2010 

TABLE EX-2 

Staff’s Proposal 

2014 2017 2019 

Original Proposal 

in January 2010 

RTC reduction = 4.5 tpd 

RTC Shave = 41% 

RTC reduction = 7.5 tpd 

RTC Shave = 67.5% 

Current Proposal RTC reduction = 4.5 tpd 

RTC Shave = 41% 

 RTC reduction = 6.1 tpd 

RTC Shave = 55% 

Note: Percentage shave is calculated using RTC holdings of 11.09 tons per day for major emitters and investors. 

Current unused RTCs based on 2008 emissions = 11.77-9.22=2.55 tpd (22% of 11.09 tons per day) 

Table EX-3 shows the new proposed BARCT levels, Tier I current BARCT levels, the percent 

reduction from Tier I and the estimated cost effectiveness for each of the seven (7) categories of 

sources located at the eleven (11) major facilities: 

TABLE EX-3 

Proposed New BARCT Levels 

Tier I (1993 

Projected BARCT 

for Year 2000) 

New BARCT 

Emission 

Reductions 

from 2005 

% 

Reduction 

from Tier I 

Cost Effectiveness 

(note 1) 

FCCUs 13.7 lbs/Mbarrels 5 ppmv 

3.25 lbs/Mbarrels 

2.88 tons/day 76% $20K - $21K per ton 

SRU/TGs Reported Value 

Avg 9.03 lbs/hour 

5 ppmv 

5.28 lbs/hour 

(note 2) 

0.73 tons/day 42% 31K - $45K per ton 

Boilers & 

Heaters 

6.76 lbs/mmscft 40ppmv 

6.76 lbs/mmscft 

0.00 tons/day 0% Not Applicable 

Sulfuric 

Acid 

Reported Value 

Avg 5.08 lbs/hour 

10 ppmv 

0.14 lbs/hour 

1.03 tons/day 97% $2K - $3K per ton 

Coke 

Calciner 

Reported Value 

Avg 2.47 lbs/ton coke 

10 ppmv 

0.11 lbs/ton coke 

0.28 tons/day 96% $10K - $23K per ton 

Container 

Glass 

Reported Value 

Avg 2.51 lbs/ton 

5 ppmv 

0.03 lbs/ton 

0.19 tons/day 99% $5K per ton 

Cement 

Kilns 

Reported Value 

Avg 0.05 lbs/ton 

5 ppmv 

0.04 lbs/ton 

 0.25 tons/day 20% $19K - $27K per ton 

Coal Fired 

Boilers 

Reported Value 95% reduction 0 tons/day ** 95% $4 K per ton 

Note: 1) The first figure of the range reflects the cost effectiveness estimated based on ETS/AEC/NEXIDEA analyses, and 

the second figure reflects the cost effectiveness estimated based on input provided by Norton Engineering. ** Equipment 

not in operation in 2005. 2) 5 ppmv is for combusted tail gas. 

The net facility investment for BARCT was estimated to be $630 million - 745 million dollars. 

The weighted average cost effectiveness was about $16 K - $19K per ton SOx reduced, with a 

range from $2K to $50K per ton SOx reduced. Figure EX-3 presents the emission reductions 

estimated from the 2005 baseline. Figure EX-4 presents the estimated costs (the present worth 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 10 November 2, 2010 

values for 25 years) based on the first set of consultants’ (ETS/AEC and NEXIDEA) estimates. 

The second consultants estimated the costs of about $750 million dollars for the proposed 

projects. 

The revised 6.1 tpd RTC reductions would be implemented over eight (8)years: 

⎯ 1.5 tons per day of reductions in compliance year 2012 

⎯ 1.5 tons per day of reductions in compliance year 2013 

⎯ 1.5 tons per day of reductions in compliance year 2014 

⎯ 0.32 tons per day of reductions in compliance year 2015 

⎯ 0.32 tons per day of reductions in compliance year 2016 

⎯ 0.32 tons per day of reductions in compliance year 2017 

⎯ 0.32 tons per day of reductions in compliance year 2018 

⎯ 0.32 tons per day of reductions in compliance year 2019 

Staff proposed to submit the first 4.5 tons per day RTC reductions to EPA to satisfy the SIP 

commitment and help the Basin meets the standard in 2015. The remaining reductions would 

be submitted at a later phase. 

FIGURE EX-3 

Emission Reduction (Tons per Day) from 2005 Baseline 

FIGURE EX-4 

Present Worth Values for 25 years (Million Dollars) Based on ETS/AEC, NEXIDEA’s and 

Norton Engineering Estimates (Excluding Cost-Ineffective Controls of >$50 K per Ton) 

SOx RECLAIM project = $630 M - $738 M, 5.4 tpd emission reductions, cost effectiveness = 

$16 K - $19K per ton. Refinery sector = $561 M - $638 M, 3.9 tpd emission reductions. 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 11 November 2, 2010 

Figure EX-5 shows the RTC reductions as proposed by staff. Figure EX-5 also shows the 

reported emissions from 2005 – 2008 and the amount of unused RTCs available in the market. 

In Figure EX-5, Curve 1 and Curve 2 represent two hypothetical but realistic emission reduction 

scenarios that use cost effectiveness as the key variable to phase-in source category compliance 

in future years. In Curve 1, it is assumed that BARCT would be implemented for cement, 

sulfuric acid, glass, and calciner by year 2014, and BARCT for FCCUs and SRU/TGs would be 

implemented after 2014. In Curve 2, it is assumed that RECLAIM facilities would implement 

voluntarily the cost-effective control measures identified by the consultants for boilers/heaters 

to meet the Tier 1 BARCT. The first dashed line in Figure EX-5 shows that because there is 

ample amount of RTCs currently available in the market comprised of unused RTCs (2.55 tpd) 

in the market, early reductions achieved at two refineries (1 tpd), and reductions from currently 

not operative cement kilns (0.25 tpd), the RECLAIM facilities will be in compliance with the 

proposed shave in 2014 without significant expenditures on BARCT for major equipment such 

as FCCUs and SRU/TGs. Implementing BARCT for FCCUs and SRU/TGs will likely take 

place after 2014 to meet the target of 2019. However, careful evaluation of the second dashed 

line in Figure EX-5 intersects with Curve 2 suggests that in perfectly operating market, many of 

the estimated expenditures for FCCU’s and SRU/TG’s controls may not be necessary after all. 

The draft CEQA analysis for this proposed rule amendment was released on August 18, 2010. 

The draft socioeconomic analysis was released with this revised draft staff report. The draft 

rule language for the proposed Rule 2002 is attached with this revised draft staff report. Rule 

development is ongoing and staff is committed to working with all stakeholders throughout the 

process. 

FIGURE EX-5 2

Staff’s Proposal and Potential Compliance Scenarios 

4

5

6

7

8

9

10

11

12

13

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Projected RTC & Emission Reductions

Sulfuric Acid

Curve 1

Curve 2

~ 5.4 tpd emission reduction      

from 2005

~ 6.1 tpd RTC reduction (55%)

Phased in: 2012–2019

Early Reduction

SRU/TGs

Cement

Glass & Calciner

FCCUs

Boilers/Heaters

Emissions ‐ Curve 1: BARCT for staff proposal. Curve 2: Additional opportunity for

reductions from boilers/heaters

RTC Reductions

Emission Reductions

SURPLUS

 

2 The assumptions used in Figure EX-5 are as follows: 1) early implementation occurred in 2008-2009; 2) In late 

2009, CPCC announced the shutdown of the cement kilns, which may or may not be permanent, and to the extent 

that when the economy improves, they plan to bring the cement kiln on-line. An assumption was made that either 

CPCC would sell their unused RTCs in 2013 or installed control equipment to achieve emission reductions; 3) 

Controls for sulfuric acid will be implemented in 2013, for glass and calciner in 2014, for FCCUs and SRUs in 2015 

– 2020; and 4) any opportunity reduction from boilers/heaters will be implemented in 2012-2015. 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 12 November 2, 2010 

Key Issues Raised by WSPA at the Refinery Committee Meeting on October 14, 2010

Staff’s original proposal presented to the Governing Board on January 8, 2010 was:

• 4.5 tpd RTC reductions by 2014 (41% shave), and

• 7.5 tpd RTC reductions by 2017 (67.5% shave)

After numerous meetings with WSPA, in August, staff revised its proposal to:

• 4.5 tpd RTC reductions by 2014 (41% shave), and

• 6.1 tpd RTC reductions by 2019 (55% shave)

WSPA indicated that it would cost the refineries $2.85 billion to comply with 60% shave. 

WSPA hired a consultant firm (ENVIRON) to collect data from the refineries and perform 

analysis with the results aggregated and de-identified. In the August 18, 2010 Refinery 

Committee Meeting, the members of the Governing Board directed staff to analyze the costs 

provided by WSPA. Staff identified three “outliers” in WSPA’s estimates that were 

substantially different from the consultants’ estimates. If the costs for these three “outliers” were 

adjusted, then the costs estimated by WSPA would be in close comparison with the consultants’ 

estimates. The three “outliers” are in the control costs of 1) Refinery 1’s FCCU, 2) Refinery 3’s 

FCCU, and 3) Refinery 3’s SRU/TG.3 Staff’s analysis was presented at the September 22 

Refinery Committee Meeting.

On October 12, 2010, WSPA revised its cost analysis to reflect staff’s proposal of 55% shave. 

The overall costs estimated by WSPA were now $1.637 billion. WSPA indicated that it would 

cost $836 million to comply with BARCT. WSPA also indicated that complying with BARCT 

would not be enough; WSPA’s members asserted that they would need to invest an additional of 

$801 million in “other” strategies to achieve additional emission reductions within WSPAmembers’ facilities to comply with the 55% shave. Table EX-3 and EX-4 show a cost 

comparison between WSPS’s proposal and staff’s proposal.

As shown in Table EX-3, staff and the consultants estimated that the refineries would reduce 

3.92 tpd by installing 4 WGSs for the FCCUs, 3 WGSs for the SRU/TGs, 1 WGS for coke 

calciner and implementing other process modification at a cost (present worth value for 25 years) 

of between $561 million - $638 million and the cost-effectiveness of $16K - $18K per ton. 

In comparison, as shown in Table EX-3, WSPA estimated that the refineries would reduce 3.81 

tpd by 1) installing 2 WGSs for FCCUs, 2 WGSs for the SRU/TGs, and 1 WGS for coke 

calciner; 2) using SOx reducing additives in the other FCCUs; and 3) implementing other 

process modification. The cost (present worth value for 25 years) of these control strategies 

proposed by WSPA and its members was estimated at $836 million and the cost-effectiveness 

was estimated at $24K per ton. Even though WSPA’s proposed main strategy does not meet 

BARCT on equipment by equipment basis (e.g. 5 ppmv for FCCUs, 5 ppmv for SRU/TGs), 

WSPA’s proposal comes very close to staff’s proposal on the actual emission reductions 

achieved (i.e. 3.81 tpd from WSPA’s proposal versus 3.92 tpd from staff’s proposal.) 

 

3 Detailed explanations are provided in Response #16 to WSPA’s comments received from March 2010 –

August 2010 in Chapter 14 - Comments & Responses of the Staff Report.
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 13 November 2, 2010 

WSPA indicated that they must invest an additional $801 million in “other” strategies shown in

Table EX-4 to secure adequate reductions at each member facility rather than relying on RTCs 

available in the open market to meet staff’s proposed shave of 55%. However, the first two of 

the “other” strategies proposed by WSPA and its members in Table EX-4 are not cost-effective: 

1) the strategy for SRU/TG is cost-ineffective at $213,277 per ton; and 2) the strategy for fuel 

gas treatment is also cost-ineffective at $104,445 per ton. While the first two strategies in Table 

EX-4 are not cost-effective, the third and fourth strategies are very cost-effective, and therefore 

would be reasonable to implement.

In addition, as shown in Table EX-5, the 55% shave would require RTC reductions in the 

amount of 5.17 tpd RTC from the refinery sector. WSPA and the refineries have demonstrated 

that they can achieve 5.31 tpd reductions with the main strategy and the two “other” (third and 

fourth) cost-effective strategies negating the need for implementing the cost-ineffective 

strategies proposed by WSPA and its members. The costs estimated by WSPA to achieve 5.31 

tpd reductions are $917 million, which reflects a cost-effectiveness of $18,925 per ton SOx 

reduced.

Furthermore, in addition to the 5.31 tpd actual reductions that can be obtained through WSPA’s 

strategies, staff estimated that there would be an additional of about 1.47 tpd potentially 

available RTCs from other sources.4 As a result, there would be about 6.57 tpd combined RTCs 

and actual emission reductions to comply with the 55% shave of 5.17 tpd reduction target 

attributed to WSPA members and subsequently this would result in a surplus of more than 1.5

tpd. 

In conclusion, staff has concluded that WSPA’s assumption for additional costs of $801 million 

for an additional of 2.12 tpd reduction would not be reasonable under a market-based program. 

 

4 The 1.47 tpd potentially available RTCs post-sahve in the market comprised of:

• 0.21 tpd post-shave remaining unused RTCs (which is calculated as follows: The surplus RTCs estimated 

from the 2005 baseline are 1.73 tpd (11.77 – 10.04 = 1.73 tpd). WSPS already accounted for 1.30 tpd 

surplus RTC in their strategy, therefore the remaining unused RTCs are 1.73 – 1.30 = 0.43 tpd pre-shave

and (0.43 tpd)(0.486) = 0.21 tpd post shave)

• 0.0009 tpd post shave hold by non-RECLAIM investors. (As of October 14, 2010, there are only two 

remaining investors that are non-RECLAIM facilities, and these two investors hold approximately 1,306 

lbs of RTCs pre-shave or 0.002 tpd pre-shave or 0.0009 tpd post-shave.) 

• 0.60 tpd from non-refinery sector. (Assuming that the non-refineries would install control technologies 

proposed by either WSPA to meet the 51.4% shave; and would have surplus RTCs to sell in the market.) 

• 0.66 tpd from refinery sector. (Assuming that the non-refineries would install control technologies 

proposed by either WSPA to meet the 51.4% shave; and would have surplus RTCs to sell in the market.) 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 14 November 2, 2010 

TABLE EX-3

Cost Comparison between WSPA’s and AQMD’s Main Strategies

Limit Reduction 

(TPD)

CE 

($/ton) Limit Reduction (TPD)

Costs 

($Million)

CE 

($/ton)

2 WGS 5 ppmv

3 DeSOx 6-35 ppmv

SRU 3 WGS 5 ppmv 0.60 174 187 $31K - 

$44K SRU

2 WGS and 

other process 

modification

5-25 ppmv 0.36 331 $101K

Other Units

1 WGS and 

other process 

modification

10 ppmv 0.31 27 62 $9K - 

$22K Other Units 

1 WGS and 

other process 

modification

Not 

specified 0.98 177 $20K

Early 

Reductions 

(FCCU, SRU)

1 WGS and 

other process 

modification

5 ppmv 1.00 - -

Early 

Reductions 

(FCCU)

1 WGS 5 ppmv 0.87 -

3.92 561 638 $16K-

$18K 3.81 836 $24K

 4 WGS 389 FCCU 328 $22K

Sub Total Sub Total

$20K -

$21K

WSPA's Main Strategy

FCCU 5 ppmv 2.01 360

AQMD's Main Strategy

Range of Costs 

($Million)

1.60

TABLE EX-4

Costs Information on WSPA “Other” Strategies

Reduction 

(TPD)

Costs 

($Million)

Cost 

Effectiveness 

($/Ton)

15 ppmv 0.13 253 213,277

<40 ppmv 0.49 467 104,445

3 projects 0.26 4 1,686

1.24 77 6,805

2.12 801 41,406

1.5 81 5,918

SRUs

Project

Total for Others

Fuel Gas Treatment

CEMS Improvements

RTCs

Total for Others 

(excluding cost-ineffective projects)

TABLE EX-5

Likely Refinery Compliance Strategy

Reduction (TPD) Costs ($Million)

3.81 836

1.5 81

5.31 917

WSPA Strategies

2. "Other" Cost-Effective WSPA Strategies

Average Cost Effectiveness = $18,925 Per Ton

1. WSPA's Main Strategy

Total Actual Reductions & Costs
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 15 November 2, 2010 

Key Issues Raised Prior to the Informational Hearing on January 8, 2010

There are four (4) key issues raised by the stakeholders: 1) BARCT determination, 2) water and 

wastewater, 3) market viability, 4) shaving methodology for facilities that are not subject to new 

BARCT, and for facilities that are subject to new BARCT. Staff’s responses to these key issues 

are summarized below: 

1) BARCT Determination 

Stakeholders commented that staff should pursue only 3 tons per day reduction as stated in the 

2007 AQMP to meet the SIP commitment. The current trend of PM2.5 is declining and does 

not warrant a SOx shave that is estimated to cost industry over one billion dollars. In addition, 

the costs and cost effectiveness were under-estimated and environmental impacts (e.g. water, 

energy) were not appropriately analyzed. 

Staff’s Response: For a market based incentive program, staff is required by the 

H&S codes to conduct periodic BARCT reassessment and demonstrate equivalency with 

command-and-control rules which would otherwise be developed as a result of BARCT 

reassessment: 

“...achieve an equivalent or greater level of emission reductions at an equivalent or 

lower cost as would have been achieved under a command-and-control rule” 

The percent RTC reduction (55%) that staff estimated for the SOx RECLAIM universe is still 

much less stringent than the percent reduction (90% - 98%) that could be imposed to specific 

categories of sources such as FCCUs, SRU/TGs, sulfuric acid plant, cement plant, coal fired 

boiler, and glass melting furnaces under the command-and-control approach. 

Furthermore, it should be noted that SOx is a significant building block of PM2.5. Chemical 

speciation of PM2.5 samples indicated that in the South Coast Air Basin 25% of the ambient 

PM2.5 is attributed to contribution from sulfates. Furthermore, SOx reductions are highly 

effective in reducing ambient PM2.5 levels as compared to other primary and secondary 

contributors to PM2.5 formation (1 tons SOx = 1.5 tons PM2.5 = 15 tons NOx). Therefore, the 

reductions of SOx are essential for the Basin to meet the federal annual standard of PM2.5 by 

2015 and the federal 24-hour average standard of PM2.5 by 2020. As indicated in the 2007 

AQMP, the control strategies included in the Plan to meet the annual PM2.5 standard when fully 

implemented will fall short of meeting the 24-hour standard by approximately 30%. Therefore, 

additional reductions above and beyond the control strategies committed in the 2007 AQMP for 

meeting the 2015 annual PM2.5 standard are necessary to meet the 24-hour PM2.5 standard in 

2020. For further information, please refer to Chapter 5 of the 2007 AQMP. 

In addition, it is worth mentioning that the U.S. EPA is proposing to set a new, more stringent, 

one-hour standard for SO2 between 50 – 100 parts per billion (ppb) and revoke the current 24-

hour of 140 ppb and the current annual standard of 30 ppb to further protect public health. The 

U.S. EPA and the state are also proposing to tighten the annual average PM2.5 standard. 

Regarding the costs and cost effectiveness analyses, after verifying the consultants’ analyses, 

staff formulated its proposal based largely on consultants’ recommendations. In response to 

comments from industry related to costs and in an effort to optimize the effectiveness of its 

proposal, staff removed the least cost effective control strategies (exceeding $50,000 per ton SOx 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 16 November 2, 2010 

reduced) from staff proposal. While these refinements to the staff proposal have reduced 

anticipated reductions by 5% (0.33 tons per day), they improved the overall cost effectiveness to 

$16 K- $19K per ton SOx reduced and reduced the total compliance costs by 25%. To further 

reduce the cost impacts, staff proposes to spread the potential emission reductions over 8 years 

starting from 2012. Staff also proposes to submit only 3 tons per day reductions to satisfy the 

SIP commitment in Phase 1 (i.e. 3 tpd reductions by 2014). The remaining reductions will be 

submitted later. 

2) Water & Wastewater Impacts 

Stakeholders commented that the water and wastewater impacts of the project would be 

significant. 

Staff’s Response: Industry argues that staff proposal will result in significant increases 

on water demand and wastewater impacts due to the water-intensive operation of wet gas 

scrubbers. To the extent that wet gas scrubbers are used to comply with the proposed SOx 

control requirements of the proposed project, staff acknowledges that the total water demand will 

increase, (by approximately 1 million gallons per day or 3 acre feet per day), but increased water 

demand over current water usage at affected facilities is well below the SCAQMD’s significance 

threshold of 5 million gallons per day of total increased water demand (i.e. potable water, 

recycled water, and groundwater). The information that staff received to date from the water 

purveyors and collected from their 2005 Urban Water Management Plans is that there are 

adequate supplies to meet the total water demand because the water demand can be largely offset 

by recycled water and groundwater sources. Availability of water supplies to meet increased 

water demand is another water demand significance threshold criterion. Even though the 

potential increase in total water demand is below the 

SCAQMD’s significance threshold of 5 million gallons per day, and because California is in a 

state of emergency for drought, staff has identified another criterion for what would be 

considered a substantial use of when determining whether a project, could be considered a 

“water demand” project as defined by CEQA. Using the more stringent criterion of what 

constitutes a potable water demand project, the potable water demand of the proposed project 

would exceed the more stringent criterion if recycled water was not utilized. Currently, recycled 

water is used at the three refineries in the basin and the water purveyors indicated that, as part of 

their Urban Water Management Plans, they are in the process of expanding their pipeline service 

to serve the remaining refineries. Therefore, in the spirit of utilizing abundance of caution, it 

was determined to classify the water impacts of the proposed project as significant and the 

impact of the proposed project can be mitigated by the use of recycled water, if available. 

Relative to the wastewater impact, staff’s analysis based on the Survey 5

 conducted among the 

affected facilities indicates that the overall wastewater increase will be less than 2% and that the 

facilities have adequate wastewater treatment capacity to treat the increase in wastewater 

generated. An increase of 25 percent would trigger a permit revision and would be considered a 

significant adverse wastewater impact. Since all of the affected facilities have been shown to 

have a potential wastewater increase less than 25 percent, no modifications to any existing 

wastewater discharge permits are anticipated as a result of the proposed project. Nevertheless, 

 

5 Staff developed a Survey Questionnaire and sent to the impacted facilities in July 2009 to collect current 

information related to water usage and wastewater generated at the facilities. The results of the responses from the 

facilities are summarized in Chapter 11 of this Staff Report. 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 17 November 2, 2010 

staff will continue working with water purveyors and the impacted facilities to further refine the 

water demand analysis and analyze other impacts and alternatives. 

3) Market Viability 

Stakeholders commented that there were not enough trading partners, the SOx market was very 

competitive and reserved, and there was an uneven distribution of RTC holdings. 

Staff’s Response: For a market based incentive program, staff is required by the H&S 

codes to conduct periodic BARCT reassessment and demonstrate equivalency with commandand-control rules which would otherwise be developed as a result of BARCT reassessment. To 

ease the issues identified by the stakeholders, staff is proposing to return a portion of the 

reductions to the facilities as a compliance margin (10%). This approach was also utilized as 

part of the 2005 NOx RECLAIM amendments. In addition, staff is proposing to establish a setaside, non-tradable reserve that could be tapped in when RTC value in the open market reach a 

certain level. Staff is also proposing to submit 4.5 tons per day reductions by December 2014 to 

meet the minimum AQMP obligation and will submit the remaining at later date no later than 

December 2019. Staff believes that compliance with a facility cap still provides the facilities 

more operational flexibilities than being subject to stringent requirements in command-andcontrol rules and regulations. 

4) Shaving Methodology 

Facilities with no equipment subject to new BARCT commented that the uniform shave was not 

equitable, would create significant difficulties for them to stay in compliance, and indicated that 

they had limited ability to buy RTCs from large facilities. While WSPA and the refineries that 

are subject to new BARCT argued strongly during the rule development process in 2008-2009 

for the use of a shave methodology that was consistent with that used during the 2005 NOx 

RECLAIM amendment. During the later phase of the rule development process, they 

commented that staff should use the 2005 as baseline for the shave, not shave the 1.98 tpd RTCs 

converted from ERCs and portion reserved for Clean Fuel projects, and not set new BARCT for 

SRU/TGs and cement kilns. 

Staff’s Response: Because of the non-uniform emissions and RTC distributions in the 

SOx RECLAIM market (11 major facilities hold 87% RTCs and contribute more than 94% of 

emissions, and the remaining 21 facilities hold only 6% RTCs and contribute about 6% of 

emissions), a uniform percent shave of 52% across the board is not the ultimate solution. The 

21 facilities that have no equipment subject to the new BARCT cannot reduce their emissions 

further, cannot sustain operation since they had limited ability to buy RTC from large facilities, 

and therefore cannot remain in compliance after the shave. To keep the 21 facilities active in 

the SOx market, staff is proposing to not shave the RTC holdings for these facilities if the RTC 

holdings are below their initial allocations provided to them at the start of the RECLAIM 

program. However, the amount of RTC holdings above their initial allocation will be shaved at 

the same rate as other 11 facilities and investors. With this approach, staff estimated that 

instead of a 52% shave across the board, the 11 facilities will have a shave of 55%, 18 of the 21 

facilities will be exempt totally from the shave, and 3 of the 21 facilities that have RTC holdings 

above their initial allocations will be shaved up to the initial allocation levels. Any trading 

from August 29, 2009 to the Governing Board hearing date will also be shaved to ensure that 

the 14 facilities subject to shave as of August 29, 2009 will not sell their RTC holdings to a 

third party investor or any of the remaining 18 facilities to avoid the shave. 
Final Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 18 November 2, 2010 

Staff used the 1997 baseline to be consistent with the approach used in the NOx 

RECLAIM adopted by the Governing Board in 2005. Using the audited 1997 baseline 

emissions, grown to 2019 based on assumptions embedded in the 2007 AQMP, would result in 

55% shave to the 11 facilities, including the refineries and investors, whereas using the audited 

2005 baseline would result in 59% shave. The emission profile changed significantly since 

1997. Active facilities have purchased RTCs from shutdown facilities to partially 

sustain/expand their facility operations. These investments would be wasted if the shave is 

based strictly on today BARCT and current emission profile. 6 However, the SRU/TGs and 

cement kilns should not be exempt from BARCT because retrofit control technologies are 

available for these sources. The 1.98 tons per day RTCs converted from ERCs at the start of the 

RECLAIM program are not inherently protected from the shave since their values were reduced 

at approximately 35% in Tier II, and furthermore, even ERCs for non-RECLAIM facilities are 

often recalled and reduced in values. 

Draft Staff Report

The attached revised Draft Staff Report includes the following information: 

⎯ BARCT determinations; 

⎯ Cost-effectiveness; 

⎯ Summary of consultants’ analyses; 

⎯ Method of determining RTC reductions and amount estimated; 

⎯ Timing of reductions; and 

⎯ Preliminary methods of applying reductions. 

Draft Staff Report changes since December 2009

Since the release of the draft Staff Reports in the Public Workshop conducted on June 23, 2009, 

and the Informational Hearing on January 8, 2010, staff modified the document as follows: 

⎯ Removed control technology recommendations with cost effectiveness larger than $50 K 

per ton (1 for FCCU, 2 for SRU/TGTUs, 1 for Boilers/Heaters) from the cost analysis, 

emission and RTC reduction analyses, 

⎯ Added achieved-in-practice information, 

⎯ Added a draft analysis on water and waste, and 

⎯ Provided responses to the comments received in the Public Workshop, 

⎯ Included analysis by Norton Engineering (NEC) and a cost effectiveness analysis based on 

NEC’s recommendations, 

⎯ Used the audited 1997 emissions in the analysis for RTC shave, 

⎯ Excluded the emission reductions of 0.85 tpd estimated from boilers/heaters since the 

proposed BARCT limit is retained at the previous BARCT level of 40 ppmv, and 

⎯ Extended the implementation period from 2017 to 2019 and reflected growth embedded in 

the 2007 AQMP. 

Staff will continue to revise the draft Staff Report as needed in the future.

 

6 Total RTCs from shutdown facilities as of today date are 1.42 tons per day of which investors have 0.83 tons per 

day. The amount of RTCs hold by investors will be shaved at the same rate as the RTCs hold by the 11 facilities 

that have equipment subject to BARCT. 
Final Staff Report – Part 1 Chapter 1 – Background

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 19 November 2, 2010

 

Chapter 1 - Background 

1.1 Legislative Authority 

The California Legislature created the Air Quality Management District (AQMD) in 1977 (the 

Lewis-Presley Air Quality Management Act, Health and Safety Code Section 40400 et seq.) as 

the agency responsible for developing and enforcing air pollution control rules and regulations in 

the South Coast Air Basin (Basin). By statute, the AQMD is required to adopt an Air Quality 

Management Plan (AQMP) demonstrating compliance with all state and federal ambient air 

quality standards for the Basin (Health and Safety Code (H&SC) §40460(a)). In addition, the 

AQMD must adopt rules and regulations that implement the AQMP (H&SC §40440(a)). 

The California Clean Air Act (CCAA) also requires the AQMD to achieve and maintain state 

standards by the earliest practicable date and for extreme non-attainment areas and to implement 

all Best Available Retrofit Control Technologies (BARCT) for existing sources. H&SC §40406 

specifically defines BARCT as “...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.” 

1.2 Fine Particle Regulation and SOx Control 

Scientific studies have found an association between exposure to particulate matter and 

significant health problems, including: aggravated asthma; chronic bronchitis; reduced lung 

function; irregular heartbeat; heart attack; and premature death in people with heart or lung 

disease. Individuals particularly sensitive to fine particle exposure include older adults, people 

with heart and lung disease, and children. 

In July 1997, the U.S. EPA promulgated the National Ambient Air Quality Standards for Fine 

Particles (PM-2.5). The annual standard is a level of 15 micrograms per cubic meter (μg/m3) 

based on a 3-year average of annual mean PM2.5 concentrations. The 24-hour standard is a level 

of 65 μg/m3, based on a 3-year average of the 98th percentile of 24-hour concentrations. In 

September 2006, EPA significantly strengthened the previous daily fine particle standard from 

65 μg/m3 to 35 μg/m3. This standard increases protection of the public from short-term exposure 

to fine particles. 

There are multiple areas across the country exceeding the federal PM2.5 standards. 

Unfortunately, Southern Californians are burdened with a disproportional share of the PM2.5 

exposure estimated to be 52 percent of the nation wide exposure resulting in approximately 

5,400 premature deaths annually. 
Final Staff Report – Part 1 Chapter 1 – Background

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 20 November 2, 2010

 

In March 2007, EPA issued a final rule, known as the Clean Air Fine Particle Implementation 

Rule, requires non-attainment areas to meet PM 2.5 standards by 2010. The Basin is classified as 

a non-attainment area and the District must develop an Air Quality Management Plan by 2008 to 

address the implementation processes to substantially reduce PM2.5 in order to meet the PM2.5 

standards by 2010. The attainment date of 2010 may be extended for up to five years; however 

the District must achieve PM2.5 standards as expeditiously as possible, no later than 2015. The 

recently adopted AQMP revision in 2007 serves as the region’s attainment demonstration to the 

federal ozone and PM2.5 standards and includes a formal request to the U.S. EPA to extend the 

PM2.5 attainment date to 2015. 

Five main types of pollutants contribute to ambient PM2.5 concentrations: direct PM2.5 

emissions, sulfur dioxide, nitrogen oxides, ammonia and volatile organic compounds. The effect 

of reducing emissions of each of these pollutants varies by areas depending on the composition, 

concentrations of these pollutants and other area-specific factors. The EPA’s Clean Air Fine 

Particle Implementation Rule requires the District to implement all reasonably available control 

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

and technical feasibility and other factors that are needed to show that the area will attain the fine 

particle standards as expeditiously as practicable. In this Clean Air Fine Particle Implementation 

Rule, the U.S. EPA specifically requires the non-attainment areas to evaluate all control 

measures to reduce direct PM2.5 emissions, as well as PM2.5 precursors, especially SOx. While 

the 2007 AQMP lays out a multi-pollutant control strategy to demonstrate attainment with the 

federal PM2.5 standards, it identifies NOx and SOx reductions by far as the two most effective 

tools in reaching attainment with the PM2.5 standards. 

1.3 Current RECLAIM Program 

On October 15, 1993, the District’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 41 SOx and 392 NOx facilities in 1993. By 

the end of 2005 compliance year, the program includes 33 SOx and 304 NOx facilities. 

Under the RECLAIM program, facilities are issued SOx and NOx annual allocations, or also 

known as facility caps. The facility caps declined annually to reflect the levels of BARCT that 

were envisioned to be in place at the RECLAIM facilities. To meet the annual declining 

allocation, RECLAIM facilities have the flexibility of installing pollution control equipment, 

changing operations, or purchasing RECLAIM Trading Credits (RTCs). It was envisioned that a 

BARCT analysis be conducted every three years to capture any advancement in control 

technology and to assure that the RECLAIM program would achieve emission reductions as 

expeditiously as possible. 

Throughout the years, there have been a number of amendments to the RECLAIM rules. In 

January 2005, a BARCT analysis was re-conducted for NOx, and as a result of this analysis, the 
Final Staff Report – Part 1 Chapter 1 – Background

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 21 November 2, 2010

 

RECLAIM rules were amended and the NOx annual allocations previously given to the NOX 

RECLAIM facility were further reduced by approximately 20% to reflect BARCT. 

For SOx, the annual allocations given decline annually from 1993 until 2003, and remain 

constant since 2003. The 2003 SOx allocations reflected the BARCT levels envisioned for SOx 

in 1993. BARCT analysis for SOx has not been reevaluated since 1993, and is reevaluated with 

this proposed amendment. 

1.4 Control Measure CMB-02 

Control Measure CMB-02 estimated that BARCT would be implemented to achieve 

approximately 3 tons per day SOx emission reductions from 2011 to 2014. The control measure 

estimated that reducing sulfur content in refinery fuel gas could achieve approximately 1.6 tons 

per day SOx; and reducing SOx emissions from fluid catalytic cracking units could achieve 1.3 

tons per day SOx. It was expected that the control measure implementation may either affect all 

SOx RECLAIM facilities or only affect the facilities that have highest SOx emissions and that 

can employ BARCT. During the rulemaking process, it was envisioned that staff will also 

explore the feasibility to incorporate the control concept of Control Measure MCS-01 - Facility 

Modernization to achieve reductions beyond 2014. 

1.5 Affected Facilities 

Currently, there are 32 facilities in the SOx RECLAIM Program. Six of the 32 facilities are 

refineries with substantial operational capacities compared to 150 refineries in the U.S, and 

Chevron and BP are the two largest refineries in the state of California based on the operational 

capacities reported. 7 These 32 RECLAIM facilities have SOx emissions greater than or equal to 

four tons per year in 1990 or any subsequent year. SOx facilities in the RECLAIM program 

have a wide range of equipment such as Fluidized Catalytic Cracking Units (FCCU), furnaces, 

kilns, sulfuric acid plants, tail gas units, boilers, heaters, internal combustion engines, and gas 

turbines. The emission inventory of these facilities and the top emitters at these facilities is 

discussed in Chapter 1, Section 1.7. 

 

7 Operable capacities of six refineries and their ranks compared to 150 refineries in the U.S. 

Refinery Capacity 

(Barrels per Day) Rank in the U.S. 

Chevron 279,000 17 

BP West Coast Products LLC 265,000 18 

ExxonMobil 149,500 47 

ConocoPhillips 139,000 52 

Tesoro 96,860 64 

Ultramar Inc. 80,887 71 

Reference: The U.S. Energy Information Administration, www.eia.doe.gov/neic/rankings/refineries.htm, 

July 2010. Refinery individual crude capacity data were reported by individual refinery as of January 1, 

2009. See Appendix E. 
Final Staff Report – Part 1 Chapter 1 – Background

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 22 November 2, 2010

 

1.6 2007 Air Quality Management Plan 

The 2007 Air Quality Management Plan (AQMP) was based on the 2002 base year inventory. In 

the 2007 AQMP, RECLAIM facilities were reported to emit a total of 12 tons per day SOx as 

shown in Table 1-1. In 2002, the SOx emissions from RECLAIM represented more than 50% of 

the total SOx emissions from stationary sources, and 23% of the total SOx emissions from the 

entire basin. 

TABLE 1-1 

Summary of Emissions by Major Source Category (2002 Base Year) 

(Tons per Day) 

Source Category NOx SOx 

Stationary Sources 

 Fuel Combustion 35 2 

 Waste Disposal 2 0 

 Cleaning and Surface Coatings 0 0 

 Petroleum Production and Marketing 0 7 

 Industrial Processes 0 0 

 Solvent Evaporation 

 Consumer Products 0 0 

 Architectural Coatings 0 0 

 Others 0 0 

 Misc. Processes 27 0 

 RECLAIM Sources 29 12 

Total Stationary Sources 93 22 

Total Mobile Sources 1000 31 

 TOTAL 1093 53 

Reference: 2007 AQMP. The actual emissions from RECLAIM facilities of 12 tpd were also 

reported in the “Annual RECLAIM Audit Report for the 2002 Compliance Year”, dated March 5, 

2004. Total RTCs (allocations and converted ERCs) were reported to be 13 tpd in the 2002 

RECLAIM Audit Report. 

Data presented in Table 1-1 and Figure 1-1 present a sharp distinction between the distributions 

of NOx versus SOx emissions in the basin, and explain the importance of undertaking a BARCT 

reassessment for RECLAIM facilities in this amendment of Regulation XX. As shown in Table 

1-1 and Figure 1-1, the RECLAIM facilities contribute to only about 3% of the NOx emissions 

in the entire South Coast Air Basin (Basin). A majority of NOx emissions in the Basin comes 

from mobile sources. In contrast, the RECLAIM facilities contribute to more than 23% of SOx 

emissions in the Basin and more than 50% of SOx emissions from stationary sources. 

The top 10 ranking sources of SOx emissions in the basin in 2002, 2014 and 2023 are shown in 

Table 1-2. SOx emissions from RECLAIM facilities are ranked #2, second only to ships and 

commercial boats. Given the effectiveness of the SOx reduction in improving PM2.5 air quality 
Final Staff Report – Part 1 Chapter 1 – Background

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 23 November 2, 2010

 

and ultimately reaching the federal PM2.5 standards, searching for additional emission 

reductions in RECLAIM category sources becomes an important effort. 

FIGURE 1-1 

NOx and SOx Emission Distribution (2002 Baseline) 

NOx Emissions 

RECLAIM

23%

Non-RECLAIM

19%

Mobil Sources

58%

 SOx Emissions

TABLE 1-2 

Top Ten Ranking of SOx Emissions from Highest to Lowest 

 2002 Base Year 2014 Base Year 2023 Base Year 

1 Ships & Commercial Boats Ships & Commercial Boats Ships & Commercial Boats 

2 RECLAIM Sources RECLAIM Sources RECLAIM Sources 

3 Non-RECLAIM Sources Aircraft Aircraft 

4 Heavy-Duty Diesel Trucks Manufact/Industrial Combustion Manufact/Industrial Combustion 

5 Aircraft Light-Duty Passenger Cars Light-Duty Passenger Cars 

6 Trains Light-Duty Trucks Light-Duty Trucks 

7 Off-Road Equipment Service/Commercial Combustion Service/Commercial Combustion 

8 Light-Duty Passenger Cars Non-RECLAIM Sources Non-RECLAIM Sources 

9 Manufact/Industrial Combustion Waste Burning & Disposal Waste Burning & Disposal 

10 Light-Duty Trucks Residential Fuel Combustion Residential Fuel Combustion 

Reference: 2007 AQMP. Note that Non-RECLAIM sources are sources that are not included in the RECLAIM 

program such SOX emissions emitted from flares or generated under upset conditions. 

The 2007 AQMP calls for significant reductions of SOx from both stationary and mobile sources 

by 2014. As shown in Table 1-3, a regional modeling in the 2007 AQMP indicates that an 

overall emission reduction of 24 tons per day SOx is needed to meet the particulate standard in 

2014. In that 24 tons per day reduction, mobile source control measures from California Air 

Resources Board and the District can potentially reduce 21 tons per day. The remaining 3 tons 

per day reductions comes from the stationary source control measure for RECLAIM facilities. A 

BARCT reassessment for SOx is therefore essential to identify the potential sources that can 

generate the 3 tons per day SOx reduction required for 2014. 

RECLAIM

3%

Non-RECLAIM

6%

Mobil Sources

91%
Final Staff Report – Part 1 Chapter 1 – Background

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 24 November 2, 2010

 

TABLE 1-3 

Emission Reductions for 2014 Based On 

Average Annual Emissions Inventory (tons per day) 

Sources SOx 

Year 2014 Baseline 43 

Emission Reductions: 

• District’s Short Term/Mid-Term Stationary Source Control Measures 3 

• CARB’s Proposed State Strategy 20 

• District’s Proposed Mobile Source Control Measures 1 

Total Reductions (All Measures) 24 

2014 Remaining Emissions 19 

Reference: Table 4-10 of 2007 AQMP 

1.7 2005 Annual Emissions Report 

RECLAIM facilities reported a total of 10 tons per day SOx from January to December 2005. 

As shown in Table 1-4, the top twelve SOx emitting facilities emitted 9.47 tons per day SOx, 

which are about 95% of total emissions from RECLAIM universe. The top 11 emitting facilities 

where staff will focus in to find the sources of emission reductions include: 

─ Six refineries: BP, ConocoPhillips, Chevron, ExxonMobil, Ultramar, and Equilon (Tesoro.) 

─ Two sulfuric acid plants: Rhodia Inc. and ConocoPhillips 

─ One coke calciner plant: BP located in Wilmington 

─ One cement manufacturing plant: California Portland Cement Co. 

─ One container glass manufacturing plants: Owns Brockway Glass Container Inc. 

TABLE 1-4 

SOx Emissions at RECLAIM Facilities (Compliance Year 2005) 

Facility 

ID Facility Name Cycle Emissions 

(tons per year) 

Emissions 

(tons per day) 

Cumulative 

Percentage 

131003 BP WEST COAST PROD.LLC BP CARSON REFINERY 2 679.4 1.86 19% 

800363 CONOCOPHILLIPS COMPANY 2 421.2 1.15 30% 

114801 RHODIA INC. 1 410.7 1.13 42% 

800370 EQUILON (Now is TESORO) 1 363.6 1.00 52% 

800030 CHEVRON PRODUCTS CO. 2 362.5 0.99 62% 

800089 EXXONMOBIL OIL CORPORATION 1 333.5 0.91 71% 

800026 ULTRAMAR INC 1 312.8 0.86 80% 

800362 CONOCOPHILLIPS COMPANY 1 210.7 0.58 85% 

131249 BP WEST COAST PRODUCTS LLC,BP WILMINGTON 1 130.1 0.36 89% 

800181 CALIFORNIA PORTLAND CEMENT CO 2 100.5 0.28 92% 

7427 OWENS-BROCKWAY GLASS CONTAINER INC 1 74.7 0.20 94% 

108701 SAINT-GOBAIN CONTAINERS, INC. (Not in Operation) 1 55.9 0.15 95% 

 OTHER RECLAIM FACILITIES 1 and 2 165.0 0.45 100% 

Total 3621 9.92 

 Reference: Based on the 2005 Annual Permit Emissions Report (January 2005 – December 2005), the emissions 

reported for 2005 were 9.92 tons per day. Please note that the audited 2005 emissions were 3,663 lbs (10.04 tons 

per day) as shown in the 2010 Annual RECLAIM Audit Report, March 5, 2010. 
Final Staff Report – Part 1 Chapter 1 – Background

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 25 November 2, 2010

 

Table 1-5 shows the distribution of SOx emissions with respect to the equipment/processes at 

RECLAIM facilities. As shown in Table 1-5, top emitters at RECLAIM facilities include fluid 

catalytic cracking units, sulfur recovery and tail gas treatment units, refinery boilers and heaters 

burning refinery gases, coke calciner, cement kilns, sulfuric acid absorption tower and glass 

melting furnaces. Staff will focus in reassessing BARCT for these top emitters which emit more 

than 80% of SOx emissions at RECLAIM facilities. 

TABLE 1-5 

Distribution of SOx Emissions at RECLAIM Facilities 

Equipment/Processes Percentage of Emissions 

Fluid Catalytic Cracking Units 33% 

Sulfur Recovery & Tail Gas Units 10% 

Refinery Process Heaters and Boilers 31% 

Cement Kilns – Glass Melting Furnaces 7% 

Sulfuric Acid Manufacturing 12% 

Other Miscellaneous Processes/Equipment 7% 

Reference: 2005 baseline emissions 

Table 1-6 shows SOx emissions reported from 2002 to 2007, grouped by compliance year and 

calendar year (e.g. SOx emissions reported for the 2003 compliance year were the emissions 

reported from January 1, 2003 – December 31, 2003 for Cycle 1 RECLAIM facilities, and from 

July 1, 2003 – June 31, 2004 for Cycle 2 facilities. SOx emissions reported for the 2003 

calendar year were the emissions reported from January 1, 2003 – December 31, 2003 for both 

Cycle 1 and Cycle 2 facilities.) The average reported emissions from 2003 – 2007 compliance 

year were approximately 10 tpd (Staff did not include year 2002, and the years before 2002 in 

the average, because the Tier II shave started in 2003.) Year 2005 emissions are closest to the 

average, and thus stand out to be the most representative emissions for the period from 2003 – 

2007. 

TABLE 1-6 

SOx Emissions Reported by RECLAIM Facilities from 2002 – 2007 

Year 

SOx Emissions by 

Compliance Year 

SOx Emissions by 

Calendar Year 

 (tpd) (tpd) 

2002 11.84 12.17 

2003 10.56 11.08 

2004 9.85 9.85 

2005 9.92 10.13 

2006 9.81 10.24 

2007 10.27 

Average (2003 - 2007) 10.08 
Final Staff Report – Part 1 Chapter 2 – BARCT Evaluation Process

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 26 November 2, 2010

 

Chapter 2 – Best Available Retrofit Control Technology 

2.1 Definition 

Best Available Retrofit Control Technology (BARCT) is defined in California Health and Safety 

(H&S) Code §40406 as: 

“... 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.”

In addition, Section §40440(b) (1) requires the District to adopt rules that requires the use of 

BARCT for existing sources: 

“Require the use of best available control technology for new or modified sources and 

the use of best available retrofit control technology for existing sources.” 

The BARCT analysis procedure for RECLAIM is identical to any BARCT analysis procedure 

used in developing a command-and-control rule. In RECLAIM, however, the BARCT levels are 

mainly used for assessing programmatic RECLAIM Trading Credit (RTC) reductions. Unlike 

other facilities that are subject to a command-and-control rule, RECLAIM facilities are not 

required to meet the BARCT levels at all times. RECLAIM facilities are provided the flexibility 

to meet the programmatic reductions by various means, such as installing control devices or 

buying RTCs. 

It should be noted that California H&S Code §39616 requires a market incentive program to 

achieve an equivalent or greater level of emission reductions at an equivalent or lower cost as 

would have been achieved under a command-and-control rule. Since the adoption of RECLAIM 

in 1993, staff has not conducted any BARCT analysis for SOx. Starting with the 2003 AQMP, 

staff committed to conduct a BARCT analysis for RECLAIM facilities every three years to 

assure that RECLAIM and non-RECLAIM facilities are subject to the same BARCT standards 

based on state-of-the-art control technologies. 

2.2 BARCT Evaluation Process 

In order to identify BARCT meeting the definition of California Health and Safety (H&S) Code 

§40406, staff conducted the following procedure: 

2.2.1 Identify Technology That Can Achieve Maximum Degree of 

Reduction 

To identify technology that can achieve maximum degree of reduction for this project, staff 

conducted a thorough and extensive research of the: 
Final Staff Report – Part 1 Chapter 2 – BARCT Evaluation Process

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 27 November 2, 2010

 

1. Control technology (both existing technology and potential future technology) from literature 

research, consultations with manufacturers/vendors, and expert consultants; 

2. Federal, state, or other air pollution control district or agency rules/regulations; and 

3. U.S. EPA RACT/BARCT/LAER Clearinghouse, CARB database, and other state and local 

district permitting database to search for recent BACT or BARCT implementation. 

It should be noted that in the rule making process staff is not obligated or limited to look at fully 

commercialized available technologies. Sometimes staff is called upon to develop technology 

forcing rules. In this situation, staff can consider technology that has not been applied to full 

scale operations, and provide sufficient time in the rule language to assist the technology to 

reach maturity. In addition, staff can develop alternative compliance provisions to handle 

situations where the technology cannot be fully developed. 

Staff will consider feasible retrofit control technology, which is a technology that has been 

previously installed and operated successfully at a similar type of source, or has practical 

potential for application to the source (i.e. has been successfully applied to similar sources with 

similar gas stream characteristics). 

Staff will also consider currently available retrofit control technology, which is a control 

technology that 1) is being offered commercially by vendors, or 2) is in commercial 

demonstration or licensing. Technologies that are in development and testing stages are 

generally classified as not currently available, but if available in the future, will be considered in 

the BARCT determination as well. 

In July 2008, staff awarded two contracts to two individual contractors and a sub-contractor to 

conduct an independent analysis on feasible/available control technologies and assess costs and 

cost effectiveness of control technologies. The contractors were required to identify at least two 

available control technology manufacturers/vendors for each of the seven categories of sources. 

The contractors were also asked to collect the manufacturers’ performance guaranteed letters. 

The results are of staff’s work and consultants’ analyses are summarized in Chapter 3 – Chapter 

9 of this report. 

A summary of staff’s review on federal, state or other air pollution control districts’ regulatory 

requirements is shown in Appendix B of this report. 8

 

8 In addition, please also see staff’s review of regulatory requirements shown in Appendix VI of the 2007 

AQMP – RACM Demonstration. 
Final Staff Report – Part 1 Chapter 2 – BARCT Evaluation Process

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 28 November 2, 2010

 

2.2.2 Evaluate Control Effectiveness 

After the technically feasible and available control technologies were identified, staff evaluated 

the control effectiveness of the control technology using the control efficiency, or the outlet SOx 

concentration, or the emission factor reported for each control technology. These control 

effectiveness information was obtained by considering data available through permitting, source 

testing, engineering estimates, or performance guarantees by the control manufacturers/vendors. 

As part of the contracts, the contractors were required to assess the levels of emission reductions 

that could be achieved from at least two different types of control technology. The results are 

summarized in Chapter 3 – Chapter 9 of the Staff Report. 

2.2.3 Conduct Top-Down Cost Effectiveness Analysis 

After the control effectiveness is established, a top-down cost effectiveness analysis starting with 

the most effective control technology was conducted to provide information on emission 

reductions and cost effectiveness associated with different control technologies and different 

levels of control. 

The top-down cost effectiveness analysis must consider site-specific, physical limitation, as well 

as operational characteristics of the equipment at the facilities. Equipment costs, installation 

costs, annual operating costs, the useful life of the control equipment are all captured in this 

analysis to generate a cost-effectiveness factor in dollars per ton of pollutants reduced. 

Staff did not conduct a cost effectiveness analysis for this project but selected to contract this 

task to two contractors and a subcontractor. Their extensive and detailed cost analyses are 

summarized and referenced in Part II of the Staff Report. In most parts, staff was in agreement 

with the contractors’ analyses and used their costs and cost effectiveness in the scenario studies 

discussed in Chapter 12. However, in some few scenarios, staff adjusted the consultants’ 

estimate to reflect the actual conditions at the facilities.9

Establishing a cost-effectiveness factor allows a comparison of control technologies. Using the 

contractors’ costs information, staff estimated the following four types of cost-effectiveness: 

1) Individual cost effectiveness for a specific emitting source (e.g. cost effectiveness for 

each FCCU); 

2) Average cost effectiveness for the category of source (e.g. average cost effectiveness for 

five FCCUs in the Basin); 

3) Average cost effectiveness for the entire project; and 

 

9 For example, for coke calciner, the consultant used maximum operational parameters to design the control system, 

estimated costs, emission reductions, and cost effectiveness. Staff used the estimated costs from the consultant’s 

analysis but estimated cost effectiveness based on actual emission reductions not emission reductions estimated 

based on the designed operational parameters. 
Final Staff Report – Part 1 Chapter 2 – BARCT Evaluation Process

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 29 November 2, 2010

 

4) Incremental cost-effectiveness for the entire project. 

The individual cost-effectiveness is defined as the present worth value of the control technology 

divided by the total quantity of pollutants removed during the life time of a control technology. 

The average cost effectiveness is an average of all control technologies, or an average of all 

control technologies for all sources in the project. The incremental cost-effectiveness is a 

comparison of the cost and performance level of a control technology to a next more stringent 

option. 

There is no bright line cut-off of what cost effectiveness in dollars per ton should be considered 

as cost effective. The cost-effectiveness factor remains a relative measurement factor. 

The top down analysis conducted by the contractors and their results are summarized in Part II of 

the Staff Report. 

In addition to the top down analysis conducted by the contractors, staff conducted a scenario 

analysis presented in Chapter 12 where staff estimated the emission reductions and cost 

effectiveness for four scenarios of control ranging from the most stringent set of control to the 

least stringent set of control. From this analysis, staff selected a scenario that best reflected 

BARCT, “... maximum degree of reduction achievable, taking into account of ....economic 

impacts by each class or category of source.”

2.2.4 Select Best Available Retrofit Control Technology (BARCT) 

The H&S Code 40406 requires the District to take into account environmental, energy and 

economic impacts during the BARCT selection process. The energy impact of each evaluated 

control technology is the energy penalty or benefit resulting from the operation of the control 

technology at the source. An example of the energy impact includes the increase (or decrease) in 

energy consumption at the source. 

The environmental impacts are evaluated to determine whether a particular control technology 

has any impacts, either positive or negative, to the environment. An example of the 

environmental impact is the generation of wastewater discharge and solid waste. 

The economic impacts (costs and cost effectiveness) are evaluated to determine the impacts of 

staff proposal on each affected facility and to the economy of the basin as a whole. 

Staff asked the consultants to identify and quantify the environmental effects or impacts (water 

demand, wastewater treatment, solid waste, energy consumption) and provide information on 

any hazardous materials and hazardous waste, if known for each SOx reduction technique or 

technology evaluated. The consultants’ results for this analysis are in their final reports. 10

 

10 The consultants’ estimates are accurate except for the reported water demand for the SRU/TG’s wet gas 

scrubbers. The figures reported in the final report are not the same as the numbers reported in the draft report. It is 

an oversight in transferring the numbers, only for the SRU/TGs. Staff contacted the wet gas scrubber 
Final Staff Report – Part 1 Chapter 2 – BARCT Evaluation Process

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 30 November 2, 2010

 

In addition, the consultants were asked to conduct an analysis on concurrent effect on other air 

pollutants, and made comments and recommendations if there were technologies capable of 

reducing SOx, and concurrently reducing (or increasing) PM2.5, and/or CO2. The consultants 

indicated that wet gas scrubbers should have a positive effect on particulate emissions and 

minimal impact on NOx, ammonia, and volatile organic compound. Fine particulate impact will 

be lessened by reducing SO2 emissions which is PM2.5 precursor. 

After considering environmental, energy, and economic impacts of each category of seven 

sources identified by staff, the contractors proposed the BARCT levels shown in Table 2-1. 

Staff was in agreement with the consultants’ recommendation for FCCUs, SRUs/TGs, refinery 

boilers/heaters, coke calciner, and sulfuric acid manufacturing, however, staff differed in setting 

the BARCT limits for glass melting furnace and cement kilns/coal-fired boiler, and further 

removed the scenarios where the cost effectiveness was lower exceeding >$50K per ton. The 

proposed BARCT levels recommended by staff and the consultants are shown in Table 2-1. 

Refer to Chapter 3 – Chapter 9 for additional information and BARCT evaluation. 

Table 2-1 

BARCT Levels Recommended by the Consultants and AQMD 

Basic Equipment Consultants’ 

Recommendation 

AQMD’s 

Recommendation 

Fluid Catalytic Cracking Units 5 ppmv 5 ppmv 

SRUs/TGs Incinerated tail gas: 5 ppmv; 

Non incinerated tail gas: 10 ppmv 

H2S & 300 ppmv non H2S 

Incinerated tail gas: 5 ppmv; 

Non incinerated tail gas: 10 ppmv 

H2S & 300 ppmv non H2S 

Refinery Boilers/Heaters 40 ppmv 40 ppmv 

Calciner, Petroleum Coke 10 ppmv 10 ppmv 

Sulfuric Acid Mfg 10 ppmv 10 ppmv 

Container Glass Melting Furnace 1-2 ppmv (99% control) 5 ppmv 

Cement Kiln & Coal-Fired Boiler 1-2 ppmv (95% control) 5 ppmv 

Additional CEQA, Socioeconomic, and market analyses are being conducted and staff will 

continue to readjust the proposed BARCT levels if needed to satisfy the requirement of the H&S 

Code.

 

manufacturers and directly gathered the water demand information for SRU/TGs as explained in a footnote in 

Chapter 11. 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 31 November 2, 2010

 

Chapter 3 – Fluid Catalytic Cracking Units 

3.1 Process Description 

There are six refineries that operate six fluid catalytic cracking units (FCCU) in the District: 

Chevron, BP West Coast, ExxonMobil, ConocoPhillips, Ultramar and Tesoro. The FCCUs are 

classified as major sources of emissions in RECLAIM, and as such, the emissions from FCCUs 

are required to be monitored with continuous emission monitoring system (CEMS), and reported 

on a daily basis electronically to the District. A brief description of the process is presented 

below. The FCCU capacities in barrels fresh feed per calendar day reported to the U.S. Energy 

Information Administration are as follows. BP and ExxonMobil operate the two largest FCCUs 

in the state of California in terms of barrels fresh feed per calendar days processed. 

BP 101,500 barrels per calendar day 

ExxonMobil 83,500 barrels per calendar day 

Chevron 66,500 barrels per calendar day 

Valero 52,200 barrels per calendar day 

ConocoPhillips 48,700 barrels per calendar day 

Tesoro 31,958 barrels per calendar day 

The FCCU is the most important and widely used refinery process for converting heavy oils into 

more valuable gasoline and lighter products. 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. 

A schematic of a fluid catalytic cracking unit (FCCU) is shown in Figure 3-1. 

The fresh feed is preheated by heat exchangers to a temperature of 500-800 degree 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 brings it up 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 900-1000 degree 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, the coke is burned off with air and the spent catalyst is reactivated. 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 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 32 November 2, 2010

 

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. Generally, FCCUs operate in a 

completely burn mode; and in this scenario, the CO boiler might be used as a heat recovery 

device without any supplemental fuel. 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 degree Fahrenheit. 

It is during the regeneration cycle that some of the catalyst is lost in the form of catalyst fines. 

The catalyst fines escape the regenerator in both the flue gas and the hydrocarbon vapor stream 

going to the fractionation column. The FCCU is a major source of sulfur oxides, nitrogen oxides 

and particulate matter in the refinery. To control particulate emissions, flue gas from the 

regenerator is routed through a series of cyclones and electrostatic precipitators. Selective 

catalytic reduction can be used to reduce nitrogen oxides emissions. The control options for 

sulfur oxides are discussed in Section 3.3 below. 

FIGURE 3-1 

Typical Fluid Catalytic Cracking Process 

3.2 Current Allocations and Emissions 

3.2.1 Allocations 

In 1993, the six refineries in the basin were issued emission allocations to their FCCUs based on 

an emission factor (also known as Tier I emission factor) of 13.7 lbs SOx per thousand barrels 

refinery feed. The activity of each FCCU used in the allocation determination in 1993, and the 

emissions allocated to each FCCU are listed in Table 3-1. The total Tier I allocations provided 

for the six FCCUs are 2.17 tons per day. 

Regenerator Reactor 

Selective 

Catalytic 

Reduction 

CO Boiler 

 (or Waste Heat Boiler) 

Locate before or after ESPs 

Electrostatic 

Precipitators 

Cyclones -

Separators 

Ammonia 

Ammonia 

Flue Gas 

Cracked 

Hydrocarbon 

Vapors 

Heavy Oils 

Air 

Regenerated 

Catalyst 

Spent 

Catalysts 

Catalyst Fines Catalyst Fines 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 33 November 2, 2010

 

3.2.2 Emissions 

Since FCCUs are classified as major sources in RECLAIM, the SOx emissions from the FCCUs 

are monitored with CEMS and reported on a daily basis to the District. The total annual 

emissions from January 2005 – December 2005 from the FCCUs is about 3.55 tons per day as 

shown in Table 3-2. 

The FCCUs at RECLAIM facilities are not subject to any specific concentration or emission rate 

standards. RECLAIM facilities are given the flexibility to operate their equipment as long as the 

total emissions from the facility are at or below the facility emission caps. The allocations 

provided to the FCCUs since 1993 have not been adjusted even though there are commercially 

available technologies that can be used to further reduce SOx emissions from the FCCUs. In 

addition, the capacity of each FCCU may increase since the level reported in 1993, which 

warrants for a need to upgrade the capacity of the control device. 

TABLE 3-1 

SOx Allocations for FCCUs 

Facility Peak 

Year 

Emission Factor 

(lbs/1000 barrels) 

Tier I Allocations 

(lbs/year) 

Tier I Allocations 

(tons/day) 

A 1992 13.7 297,345 0.41 

B 1990 13.7 414,233 0.57 

C 1988 13.7 188,545 0.26 

D 1992 13.7 374,037 0.51 

E 1991 13.7 127,684 0.18 

F 1990 13.7 172,291 0.24 

 Total 2.17 

Reference: Allocation files for each facility developed based on reported data in 1993. 

TABLE 3-2 

Current SOx Emissions from FCCUs 

Facility 2005 SOx Emissions 

(tons/day) 

2006 SOx Emissions 

(tons/day) 

2007 SOx Emissions 

(tons/day) 

A 0.39 0.36 0.33 

B 1.03 0.70 0.71 

C 0.96 1.00 0.97 

D 0.31 0.27 0.20 

E 0.25 0.28 0.18 

F 0.61 0.89 0.56 

3.55 3.50 2.95 

Note: The 2005 SOx emissions were from SCAQMD database for the period from January 2005 – December 2005. 

The 2006 and 2007 emissions were reported by the facilities through a Survey Questionnaire distributed by 

SCAQMD in 2008. 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 34 November 2, 2010

 

Based on responses from the facilities to the 2008 SCAQMD Survey Questionnaire, staff 

estimated that the six refineries were operated at the current emission rates listed in Table 3-3.

TABLE 3-3 

Current SOx Emission Rates & Concentrations from FCCUs 

SOx Outlet Concentrations (ppmv) Emission Rate 

(lbs/1000 barrels feed) 

Average 18 ppmv 10.99 

Average 36 ppmv 21.68 

35 ppmv – 95 ppmv 34.91 

Average 12 ppmv 6.89 

Average 11 ppmv 16.67 

Average 58 ppmv 22.18 

Average of 6 Refineries 17.93 

Note: The SOx outlet concentrations at 0% O2 were either data reported by the facilities through the 

Survey conducted in 2008, or data in the source test results provided by SCAQMD source 

testing team. 

3.3 Control Technology 

The potential available control technologies to reduce SOx emissions from a FCCU are: 

1. Processing of low sulfur feed stocks, 

2. Feed hydro-treating, 

3. Flue gas scrubbing, 

4. Using SOx reducing additives, 

5. Using combination of the above control technologies 

Currently, the six refineries in the Basin have processed low sulfur feed stocks and use feed 

hydrotreating. Five refineries in the District have experimented with SOx reducing additives, 

and one refinery has chosen to install a wet scrubber to reduce SOx and PM concurrently. 

3.3.1 SOx Reducing Catalysts 

Type of Catalysts 

Developed in the late 1970s, SOx reducing catalysts were initially alumina based. However, the 

alumina based catalysts were shown to be susceptible to deactivation. In 1980, it was found that 

the potential pick-up SO3 in the regenerator was substantially increased by replacing the pure 

alumina-based catalysts with magnesium-aluminate catalysts (1 mole of magnesium per 2 moles 

of aluminum). In 1990, Akzo Nobel invented hydrotalcite, and hydrotalcite-like, compounds to 

support up to 3 to 4 moles of magnesium per mole of aluminum. In 1997, Intercat Inc. patented 

a self-supporting hydrotalcite SOx reducing catalyst, named SOXGETTER®, and GraceDavidson developed a DESOX® catalyst with significantly improved performance. In 2000, 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 35 November 2, 2010

 

Intercat Inc. commercialized Super SOXGETTER® which is advertised to be 80% better than 

SOXGETTER®, and Grace-Davidson commercialized Super DESOX®, 35% better than 

DESOX® .

11, 12

Mechanism for SOx Reduction 

In general, SOx reducing catalysts remove SOx from the regenerator flue gas and release the 

sulfur as H2S in the FCCU reactor through a three step mechanism: 

In the regenerator, sulfur bearing coke is burned to SO2; and in the presence of excess oxygen, a 

portion of SO2 is converted to SO3 

S + O2 → SO2

SO2 + 1/2O2 → SO3 

The magnesium-based reducing catalysts “pick-up” SO3 in the regenerator and form magnesium 

sulfate: 

 

 MxO + SO3 → MxSO4 

The magnesium sulfate recirculates back to the reactor, and reacts with hydrogen to form either 

magnesium sulfide and water, or magnesium oxide, and hydrogen sulfide: 

 

 MxSO4 + 4 H2 → MxS + 4H2O 

 MxS + H2O → MxO+ H2S 

MxSO4 + 4 H2 → MxO + H2S + 3H2O 

The H2S then exits the FCCU in the dry gas and must be removed by the sulfur recovery units. 

This increase in H2S, 5% - 20%, can typically be managed within a refinery’s operations. 

Performance of SOx Reducing Catalysts 

Control efficiency of SOx reducing additives depends on many factors such as 1) feed type, 2) 

starting SOx level, 3) catalyst type, 4) amount of catalysts added, and 5) FCCU’s operating 

conditions. Manufacturers of SOx reducing catalysts generally use a proprietary computer 

model to estimate the performance of their products. Typical control efficiencies are reported to 

be in a range of 70% - 87% from an uncontrolled level as shown in Table 3-4. 

 

11 Super DESOX®: Providing Bechmark Effectiveness for SOx Reduction, D. Sellery, Murphy Oil Corporation and 

B. Riley, GRACE Davison. 

12 The Role of Additives in Reducing Fluid Catalytic Cracking SOx and NOx Emissions, A. Vierheilig and M. 

Evans, Petroleum and Coal, Volume 45, 3-4, 147-153, 2003. 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 36 November 2, 2010

 

TABLE 3-4 

Commercial Results of SOx Reduction Additives 

FCC Type Kellogg UOP High Eff, UOP SBS UOP Stacked 

Combustion Mode Total Total Total Partial 

Additive SOXGETTER DESOX SOXGETTER DESOX SOXGETTER DESOX SOXGETTER

Feed Quality 

Fresh Feed Rate, MBPD 19.1 18.5 55.5 53.6 64.0 63.0 7.0 

Fresh Feed Sulfur, wt% 0.52 0.54 0.71 0.70 1.25 1.49 0.55 

Operating Conditions 

Reactor Temperature, oF 1009 1009 1006 999 1005 1005 985 

Reactor O2, vol% 1.9 1.9 0.9 1.1 1.1 1.3 1.5 

Additive Addition, lb/day 728 676 1583 2081 2125 3240 40 

 

Emissions 

Uncontrolled SOx, lb/hr 1181 1086 2046 1895 3100 3853 35 

Controlled SOx, lb/hr 154 141 286 303 868 1117 11 

Controlled SOx, ppmv 188 179 358 370 575 754 98 

Reduction % 87 87 86 84 72 71 70 

 

Additive Efficiency, lb/lb 

at equivalent SOx red 

level 

34 34 27 18 25 20 15 

Reference: The Role of Additives in Reducing Fluid Catalytic Cracking SOx and NOx Emissions, A. Vierheilig and 

M. Evans, Petroleum and Coal, Volume 45, 3-4, 147-153, 2003. 

SOx reducing catalysts also reduce PM10. In 2003, during the development of Rule 1105.1 – 

Reduction of PM10 and Ammonia Emissions from Fluid Catalytic Cracking Units, five 

refineries in the District experimented with SOx reducing catalysts supplied by Intercat Inc. and 

Grace-Davidson. Data collected from 2 refineries shown in Table 3-5 shows that with the use of 

SOx reducing catalysts, SOx and PM10 emissions could be reduced by approximately 40% - 

60%. 13

TABLE 3-5 

Application of SOx Reducing Catalysts at Two Refineries in the District 

Refinery #1 #1 #2 #2 

Test Date Oct-01 Mar-02 Aug-96 Oct-01 

SOx Reducing Additives (lbs/day) 0 178 0 1,471 

Total PM10 (lbs/hr) 11.41 6.50 128.89 48.25 

SOx (lbs/day) 2,291 1,352 4,553 1,583 

Average Period for SOx (days) 16 23 4 24 

Percent Reduction 43% for PM10, 41% for SOx 63% for PM10, 65% for SOx 

Note: The percent reduction in total PM10 with the SOx reducing additives for Refinery #1 was calculated as follows: % 

reduction = (1-(6.50/11.42))x100 = 43%. Same approach is used to estimate the percent reduction in total PM10 for Refinery # 

2, and the percent reductions in SOx emissions for both refineries. SOx emissions from FCCUs are reported on a daily basis and

staff has used an average period from 4 days to 24 days to estimate an average of SOx emissions at these 2 refineries. The 

information here was presented in the final Staff Report of Rule 1105.1, October 2003. 

 

13 Staff Report of SCAQMD Rule 1105.1 – Reduction of PM10 and Ammonia Emissions from Fluid Catalytic 

Cracking Unit, October 9, 2003. 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 37 November 2, 2010

 

Just recently, a refinery in the District voluntarily conducted a short-term testing with SOx 

reducing catalysts from September 2008 – December 2008. CEMS was used to continuously 

measured SOx. Source tests were conducted to measure SOx and PM10. The results indicated 

that SOx could be reduced to 7 ppmv, 0% O2, without any increase in PM10. A considerable 

amount of SOx reducing additives was needed throughout this period of time. The short-term 

testing proceeded without any problems to the FCCU operation. Additional long term testing 

would be needed however to ensure that a level of 7 ppmv or below was a sustainable level with 

SOx reducing catalysts. 

Costs and Cost Effectiveness for SOx Reducing Catalysts in Literature 

Commercial data from Intercat for SOXGETTER® have shown that 85% reduction in SOx, 

resulting in 50 ppmv emissions, can be achieved with an addition rate of 18 lbs SOx per pound 

of additive. Decreasing emissions to below 25 ppmv reduced the additive efficiency to below 14 

lbs SOx per pound of additive. The concentration of SOXGETTER® required to reduce 

emissions below 25 ppmv was slightly greater than 5% by weight of the total catalyst inventory. 

The relative cost increase to reduce emissions from 50 to 25 ppmv was 31%.

Figure 3-2 was built based on a manufacturer's field and laboratory experience with the additives 

and provided to staff during the development of Rule 1105.1. In this scenario, if 85% reduction 

is needed to achieve 25 ppmv SOx outlet concentration, the cost effectiveness will be 

approximately $6,000 per ton SOx removed. 14 

FIGURE 3-2 

 Efficiency of SOx Reducing Additives 

In other references shown in Table 3-6, a range of $500 - $3,000 per ton SOx reduced has been 

reported in literature. 

 

14 Staff Report of SCAQMD Rule 1105.1 – Reduction of PM10 and Ammonia Emissions from Fluid Catalytic 

Cracking Unit, October 9, 2003. 

0

1 0

2 0

3 0

4 0

5 0

6 0

7 0

8 0

9 0

100

$0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50

$/lb S O x R em oved

% SOx Reduction

A ssum ptions: 150 T on C atalyst 

Inventory, 50,000 BP D Feed 

T h is ra n ge w a s cre a te d w ith th e in d u stria l e xp e rie n ce in h e a vily 

h yd ro tre a te d u n its. A w id e va rie ty o f C a t to O il R a tio s, S ta rtin g S O x 

le ve ls, F e e d typ e s, R e ge n e ra to r C o n d itio n s (in clu d in g fu ll a n d p a rtia l 

b u rn ), S trip p in g E fficie n cy, a n d U n it S ize s w a s ta ke n in to 

co n sid e ra tio n to co ve r th e e xp e cte d u n ive rse o f co m m e rcia l 

o p e ra tio n s.
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 38 November 2, 2010

 

Through the 2008 Survey Questionnaire, the refineries reported that they currently use Intercat 

SUPER SOXGETTER and Grace Davison SUPERDESOX at a rate of $6 - $8 per pound at an 

addition rate of 220 lbs/day – 800 lbs/day to the FCCUs.

TABLE 3-6 

Cost Effectiveness of SOx Reducing Catalysts 

SOx Level Cost Effectiveness 

7 ppmv at 0% O2 (short-term testing) $18,941 per ton (3)

25 ppmv at 0% O2, 365 day average and 

50 ppmv at 0% O2, 7-day rolling average 

$500 - $880 per ton (1)

50% reduction from uncontrolled level $2,000 - $3,000 per ton (2)

Note: 1) Assessment of Control Options for Petroleum Refineries in the Mid-Atlantic Region – Final Technical 

Support Document. Prepared by MACTEC Federal Programs, Inc. for the Mid-Atlantic Regional Air Management 

Association (MARAMA), January 31, 2007. 2) Reducing Refinery SOx Emissions. E. Butler, K. Groves, J. 

Hymanyk of Chevron Canada Limited and M. Maholland, P. Clark, and G. Aru of Intercat Inc. Petroleum Technical 

Quarterly, Quarter 3, 2006. 3) Short-term testing with SOx reducing additives at a refinery in the District. 

3.3.2 Wet Gas Scrubbers 

Wet scrubbing is used to control both SOx and particulate. There are two types of wet scrubbing 

that are typically used for FCCUs, the caustic-based non-regenerative wet scrubbing and the 

regenerative scrubbing. Both systems can achieve a level of less than 5 ppmv demonstrated at 

several refineries in the U.S. as shown in Table 3-7. 

Non-Regenerative Wet Gas Scrubbers 

Non-regenerative wet scrubbing is a proven control technology for many decades and there are 

many manufacturers in the U.S. Typically, caustic soda (NaOH) is used as the alkaline 

absorbing reagent for SO2. Other alkaline reagents, such as soda ash and magnesium hydroxide, 

can also be used. The absorbents capture SO2, and convert SO2 to various types of sulfites and 

sulfates (NaHSO3, Na2SO3, Na2SO4). Acid mist (H2SO4) is also captured. The sulfites and 

sulfates are later separated in a purge treatment system and the treated water, free of suspended 

solids, are either discharged or recycled. One example of the caustic-based non regenerative 

scrubbing system is the proprietary EDV (Electro Dynamic Venturi) scrubbing system offered by 

BELCO Technologies Corporation, shown in Figure 3-3.15, 16

An EDV scrubbing system consists of three main modules 1) a spray tower module, 2) a filtering 

module, and 3) a droplet separator module. The flue gas enters the spray tower module, which is 

an open tower with multiple layers of spray nozzles. The nozzles supply a high density stream of 

 

15 Evaluating Wet Scrubbers, Edwin H. Weaver of BELCO Technologies Corporation, Petroleum Technology 

Quarterly, Quarter 3, 2006.

16 A Logical and Cost Effective Approach for Reducing Refinery FCCU Emissions. S.T. Eagleson, G. Billemeyer, 

N. Confuorto, and E. H. Weaver of BELCO, and S. Singhania and N. Singhania of Singhania Technical Services 

Pvt., India, Presented at PETROTECH 6th International Petroleum Conference in India, January 2005.
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 39 November 2, 2010

 

caustic water, which travels countercurrent with the gas flow, circles, encompasses, wets, and 

saturates the flue gas. Multiple stages of liquid/gas absorption occur in the spray tower module. 

SO2 and acid mist are captured and converted to sulfites and sulfates. Large particles in the flue 

gas are also removed by impaction with the water droplets. 

The flue gas saturated with heavy water droplets continues to move up the wet scrubber to the 

filtering module. In here, the flue gas reaches super-saturation. Water further condenses and 

agglomeration of fine particles in the gas stream takes place. The size and mass of the fine 

particulate in the gas stream continue to increase. The flue gas, super-saturated with heavy water 

droplets, then enters the droplet separator module. The droplet separator module consists of a 

bank of parallel spin vanes. The heavy, super-saturated, water droplets impinge on the walls of 

these spin vanes, and are drained to the bottom of the wet scrubber. The filtering module and 

the droplet separator modules are important components of the wet scrubber to control fine 

particulate. 

The spent caustic water purged from the wet scrubber is typically processed in a purge treatment 

shown in Figure 3-4. In the purge treatment unit, a clarifier is used to remove suspended solids 

which are later disposed. The effluent from the clarifier is oxidized with agitated air. Sulfites 

are converted to sulfates, and the chemical oxygen demand (COD) is further reduced so that the 

effluent can be safely discharged to the waste water system. 

Regenerative Wet Gas Scrubbers 

The regenerative wet gas scrubbing process removes the SO2 from the flue gas with a buffer that 

can be regenerated. The buffer is sent to a regenerative plant where the SO2 is extracted from 

the buffer as concentrated SO2. The concentrated SO2 is then sent to a sulfur recovery unit 

(SRU) to recover sulfur as byproducts, such as liquid SO2, sulfuric acid or elemental sulfur. 

Where the inlet concentrations of SO2 are high and a significant amount of byproducts can be 

generated and sold to be used in the fertilizer, chemical, pulp and paper industries, the use of 

regenerative wet gas scrubber is favored over non-regenerative wet gas scrubber. One example 

of a regenerative scrubber is the proprietary LABSORB offered by BELCO Technologies 

Corporation. 17, 18 

 

17 Evaluating Wet Scrubbers, Edwin H. Weaver of BELCO Technologies Corporation, Petroleum Technology 

Quarterly, Quarter 3, 2006. 

18 A Logical and Cost Effective Approach for Reducing Refinery FCCU Emissions. S.T. Eagleson, G. Billemeyer, 

N. Confuorto, and E. H. Weaver of BELCO, and S. Singhania and N. Singhania of Singhania Technical Services 

Pvt., India, Presented at PETROTECH 6th International Petroleum Conference in India, January 2005.
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 40 November 2, 2010

 

FIGURE 3-3 

 EDV Non-Regenerative Wet Scrubbing System Developed By BELCO 

rRefeReference: Evaluating Wet Scrubbers, E.H.Weaver, 2006. 

FIGURE 3-4 

Purge Treatment System 

The LABSORB scrubbing process, as shown in Figure 3-5, uses a patented non-organic aqueous 

solution of sodium phosphate salts as a buffer. This buffer is made from two common available 

products, caustic and phosphoric acid. The LABSORB scrubbing system is capable of reducing 

High Capacity Clarifier 

Solids to Disposal

Oxidation Units

Effluent Discharged

Purge from 

Scrubber 

Air 

SPRAY MODULE 

Filtering Module 

Recirculation Pumps

FILTERING MODULE 

Absorber Vessel 

Recirculation Pumps 

Flue Gas Inlet

DROPLET SEPARATOR MODULE 

Flue Gas Outlet

Purge Stream Caustic Reagent Inlet 

Makeup Water Inlet
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 41 November 2, 2010

 

SOx to 25 ppmv or less. The LABSORP system consists of 1) a quench pre-scrubber, 2) an 

absorber, and 3) a regeneration section which typically includes a stripper and a heat exchanger. 

In the scrubbing side of the regenerative scrubbing system, the quench pre-scrubber is used to 

wash out the large particles carried over, as well as acid components in the flue gas such as HF, 

HCl and SO3. The absorption of SO2 is carried out in the absorber. The absorber is typically a 

single high-efficient packed bed scrubber, packed with high-efficient structural packing 

materials. In some scenarios, such as when the inlet SO2 concentration is low, a multiple-staged 

packed bed scrubber, or a spray and plate tower scrubber, is recommended to achieve an outlet 

concentration of 25 ppmv or less. 

In the regenerative side of the regenerative scrubbing system, the SO2-rich buffer stream is first 

heated by steam to vaporize the water and remove it from the buffer. The buffer stream is then 

sent to a stripper/condenser to separate the SO2 from the buffer. The buffer free of SO2 is 

returned to the buffer mixing tank while the condensed-SO2 gas stream is sent back to the SRU 

for further treatment. 

FIGURE 3-5 

LABSORB Regenerative Wet Scrubbing System Developed By BELCO 

Quench 

Scrubber 

Packed 

Bed 

Absorber 

Heat 

Exchangers 

Clarifier 

Flue Gas from CO 

Boiler (>1000 

ppmv SO2) 

Water

Flue Gas to 

Stack (<25 

ppmv SO2) 

Water to Treatment 

or Discharged 

Stripper 

Steam

Condensed 

SO2 to SRU 

Buffer 

Tank 

Solids to 

Disposal 

SCRUBBING SIDE REGENERATION SIDE

Condensate
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 42 November 2, 2010

 

A regenerative wet gas scrubber typically costs more than a non-regenerative unit to install. 

BELCO Inc. estimated that the capital cost of a regenerative system is about 2.4 times the capital 

cost of a non-regenerative system, primarily due to the additional complexity of the regenerative 

wet scrubbing system. However, the regenerative system has a significant advantage in annual 

operating costs because the alkaline absorbing buffer in the regenerative system can be 

regenerated, low amount of reagents used in the regenerative system, and the byproducts (e.g. 

elemental sulfur) can be sold. The annual operating costs of a regenerative system are estimated 

to be about 35% of the annual operating costs of a non-regenerative system as shown in Table 3-

7. Table 3-8 presents an estimate for cost effectiveness of the wet gas scrubber reported in 

literature, ranging from $500 - $3,000 per ton to achieve 25 ppmv. As shown later, a 5 ppmv 

and lower level has also been achieved. The consultants and staff’s estimated a cost 

effectiveness of $12,000 - $76,000 per ton to achieve 5 ppmv level as shown in Chapter 12 of 

this report. 

TABLE 3-7 

Capital Costs and Annual Operating Costs of Regenerative Wet Gas Scrubbing System 

 

Type of Costs Percent Of Costs Comparing to Non-Regenerative WGS 

Capital Costs: 240% of Non-Regenerative WGS’s 

Operating Costs: 

Caustic 18% 

Power 35% 

Make-Up Water Less than 5% 

Water Discharge Less than 5% 

Solids Disposal Less than 5% 

Operating & Maintenance 20% 

Steam 10% 

Cooling Water Less than 5% 

Phosphoric Acid 5% 

Reference: Evaluating Wet Scrubbers, Edwin H. Weaver of BELCO Technologies Corporation, Petroleum 

Technology Quarterly, Quarter 3, 2006.

TABLE 3-8 

Cost Effectiveness for Wet Gas Scrubbers 

SOx Achieved Level Cost Effectiveness 

5 ppmv at 0% O2, 365 day average $12,000 - $76,000 per ton (2)

25 ppmv at 0% O2, 365 day average 

50 ppmv at 0% O2, 7-day rolling average 

$500 - $3,000 per ton (1)

Note: 1) Assessment of Control Options for Petroleum Refineries in the Mid-Atlantic Region – Final Technical 

Support Document. Prepared by MACTEC Federal Programs, Inc. for the Mid-Atlantic Regional Air Management 

Association (MARAMA), January 31, 2007. 2) Refer to the consultants’ report for this project. The high end 

$76,000 per ton was for a refinery that already has the feed extensively hydrotreated to a level slightly above 10 

ppmv. 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 43 November 2, 2010

 

3.4 Achieved-In-Practice Information 

As shown in Table 3-9, there is an extensive list of refineries in the U.S. have been installed wet 

gas scrubbers or use SOx reducing catalysts to meet a typical U.S. EPA current standard of 25 

ppmvd SO2 at 0% O2, 365-day rolling average; 50 ppmvd at 0% O2, 7-day rolling average set 

through various consent decrees since 2001. 

TABLE 3-9 

SOx Control Technology for FCCUs 

Refinery SOx Limit Technology Implementation 

Marathon Petroleum Co 

LLC., Garyville Refinery, 

Louisiana (1)

25 ppmvd at 0% O2, 365-day rolling 

average 

Wet Gas Scrubber NA 

BP, Texas City, Texas (4) 25 ppmvd at 0% O2, 365-day rolling 

average 

Wet Gas Scrubber & 

SOx Reducing Catalysts 

2006 

Valero Delaware City. 

FCCU w CO boiler (2), (5)

25 ppmvd at 0% O2, 365-day rolling 

average; 50 ppmvd at 0% O2, 7-day 

rolling average. Achieved 1 ppmv – 

2ppmv SOx, 0% O2. 

Wet Gas Scrubber 

BELCO & CANSOLV 

By 2006 

ConocoPhyllips Bayway. 

FCCU w two CO boilers.

(2)

25 ppmvd at 0% O2, 365-day rolling 

average; 50 ppmvd at 0% O2, 7-day 

rolling average. 

Wet Gas Scrubber By 2005 

ConocoPhyllips Trainer. 

FCCU w two CO boilers.

(2)

25 ppmvd at 0% O2, 365-day rolling 

average; 50 ppmvd at 0% O2, 7-day 

rolling average. 

Wet Gas Scrubber By 2006 

 Motiva, Convent, LA (2) 25 ppmvd at 0% O2, 365-day rolling 

average (225,000 barrels per day 

capacity FCCU) 

Wet Gas Scrubber 2006 – 2007 

Motiva, Port Arthur, TX (3) 25 ppmvd at 0% O2, 365-day rolling 

average (235,000 barrels per day 

capacity FCCU) 

Wet Gas Scrubber 2001 

Equilon, Wilmington, CA 25 ppmvd at 0% O2, 365-day rolling 

average (99,000 barrels per day 

capacity FCCU) 

SOx Reducing Catalysts 2001 

Equilon, Martinez, CA (3) 25 ppmvd at 0% O2, 365-day rolling 

average (155,000 barrels per day 

capacity FCCU) 

SOx Reducing Catalysts 2001 

Equilon, Anacortes, WA 

(3)

25 ppmvd at 0% O2, 365-day rolling 

average (145,000 barrels per day 

capacity FCCU) 

Wet Gas Scrubber 2006 

Deer Park Refining, Deer 

Park, TX (3)

25 ppmvd at 0% O2, 365-day rolling 

average (340,000 barrels per day 

capacity FCCU) 

Wet Gas Scrubber 2003 

Note: 1) The U.S. Environmental Protection Agency RACT/BACT/LAER Clearinghouse; 2) Assessment of Control Options for 

Petroleum Refineries in the Mid-Atlantic Region – Final Technical Support Document. MACTEC Federal Programs, Inc. for 

Mid-Atlantic Regional Air Management Association (MARAMA), January 31, 2007; 3) Motiva Enterprises LLC, Equilon 

Enterprises LLC, and Deer Park Refining Limited Partnership Civil Judicial Settlement, March 21, 2001; 4) BP Texas City Site 

– Texas City, Texas – 2004 Environmental Statement, June 2005. 5) Valero installed two wet gas scrubbers for the FCCU and 

fluid coker units continuously achieved 1 ppmv – 2 ppmv SOx, at 0% O2 in the past 2 years. 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 44 November 2, 2010

 

An extensive study by a refinery in Canada indicates that wet gas scrubbers are commonly used 

to achieve an emission reduction of 95%, while reducing additives are routinely being used to 

achieve 85% - 90% reduction. 19 As shown in Table 3-9, it seems that SOx reducing catalysts 

are typically the choice for FCCUs with average capacity of less than 150,000 barrels feed per 

day, while wet gas scrubbers are typically the choice for FCCUs with capacity higher than 

150,000 barrels per day. 

Achieved-In-Practice Information for 5 PPMV Using Wet Gas Scrubbers 

In the past several months, District staff contacted many air pollution control agencies 

throughout the nation to collect the performance information for the FCCU’s wet gas scrubbers. 

Some air pollution control agencies do not require a facility to submit CEMS data, and in this 

case, the agencies provide staff with source test or RATA information. 

To date, staff received the performance data of ten FCCU’s wet gas scrubbers. All ten FCCU’s 

wet gas scrubbers achieved a level below 18 ppmv. Six out of the ten FCCUs overly surpassed 

the performance of a typical wet gas scrubber (i.e., 25 ppmv SO2 at 0% O2, 365-day rolling 

average and 50 ppmvd at 0% O2, 7-day rolling average required by the U.S. EPA.) Staff was 

informed that many facilities choose not to lower the SOx level below the level required by the 

U.S. EPA. However, lower SOx levels are achievable by scrubbing the flue gases with more 

caustic solution at a higher pH level. Staff identified six facilities that opted to achieve these 

lower SOx levels. The resulting emissions from these six outstanding refineries are shown in 

Table 3-10, which demonstrate that wet gas scrubbers can achieve a level below 5 ppmv at 0% 

O2 in practice. 

 

19 Reducing Refinery SOx Emissions. E. Butler, K. Groves, J. Hymanyk of Chevron Canada Limited and M. 

Maholland, P. Clark, and G. Aru of Intercat Inc. Petroleum Technical Quarterly, Quarter 3, 2006. 
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 45 November 2, 2010

 

TABLE 3-10 

Achieve-in-Practice Level for FCCU’s Wet Gas Scrubbers 

Facility Control Equipment 

Manufacturer 

Start-Up SO2 Method (CEMS or 

Source Test) 

A Refinery in 

SCAQMD (1)

Wet gas non-regenerative 

scrubber/wet ESP as polisher 

2008 < 5 ppmv Source Test & CEMS 

(10/2008) 

Valero 

Delaware City, DE (2)

BELCO/CANSOLV – 

regenerative packed bed scrubber 

2006 1-2 ppmv CEMS (1/2008 – 

6/2009) & Source Test 

Conoco Phillips 

Ferndale, WA(3)

BELCO 2002 3.87 ppmv RATA (5/13/08) 

Lion Oil 

El Dorado, AR (4)

BELCO 2002 2.65 ppmv Source Test 

Placid Refining 

Port Allen, LA (5)

BELCO 2008 < 1 ppmv Source Test (2/19/09) 

Citgo (FCCU-A) 

Lake Charles, LA (5)

BELCO 2005 1.87 ppmv RATA (9/13 and 

9/14/05) 

Note: 

1) Source test data was conducted in October, 2008. CEMS data was submitted to SCAQMD by the refinery. Concentration was estimated by 

SCAQMD staff based on the average refinery gas throughputs. CEMS/source test data shown in Appendix C of this report. 

2) Telephone conversations and emails between Minh Pham (SCAQMD) and Ravi Rangan of Delaware Department of Natural Resources and 

Environmental Control (DNREC) between April 2008 and July 2009. Permit for Delaware City Refinery (aka Premcor Refining) is now owned 

by Valero. Source test and CEMS data provided by DNREC. The unit includes a BELCO pre-scrubber, an amine-based regenerative 

CANSOLV packed-bed absorber, and a caustic polisher to reduce both SOx and particulate emissions for their FCCU and their fluidized coker 

unit (FCU). The system for the FCCU is to treat an inlet flow of 442,400 scfm, and 258,200 scfm for FCU. The system is to reduce 97% 

emissions from FCCU, and 99% emissions from FCU. The systems were in operation since 2006, and continuously achieved levels of 1 ppmv 

– 2 ppmv SOx, 0% O2. Extensive CEMS data were provided by air quality engineer of Delaware City. The capacity of this refinery FCCU is 

about twice bigger than the largest refinery FCCU in the District. 

3) Telephone conversations and emails between Kevin Orellana (SCAQMD) and Toby Allen of Northwest Clean Air Agency between July and 

November 2009. 

4) Telephone conversations and emails between Kevin Orellana (SCAQMD) and Mary Pettyjohn of Arkansas Department of Environmental 

Quality in August 2009. 

5) Telephone conversations and emails between Kevin Orellana (SCAQMD) and Tim Bergeron of Louisiana Department of Environmental

Quality between August and November 2009 

3.5 Proposed BARCT Level and Emission Reductions 

The consultants (ETS/AEC) recommended a BARCT level of 5 ppmv at 0% O2, 365-day 

average for all remaining five FCCUs based on the solid achieve-in-practice performance of a 

wet gas scrubber at the refinery in the District for the past 6 months. The estimated emission 

reductions and cost effectiveness based on ETS/AEC are shown in Table 3-11 

TABLE 3-11 

Emission Reductions & Cost Effectiveness Estimates (ETS/AEC) 

 

Refinery: 1 2 3 4 5 6 Total 

Emissions Reduction (tpd) 0.58 0.19 0.28 0.20 0.87 0.94 3.07 

Cost Effectiveness 

(ETS/AEC) 

$14.4k $76.2k $36.6k $42.1k $11.6k $12.8k $20.8k

$24.6k

Reference: Table EX-1 of ETS/AEC Final Report for Module 3A, April 20, 2009
Final Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 46 November 2, 2010

 

Since there are at least six refineries in the U.S. successfully operating wet gas scrubbers to 

achieve a level below 5 ppmv, staff concurred with the consultants’ recommendation, and 

proposed to set BARCT for FCCUs at 5 ppmv, 0% O2, 365-day average. However, because 

Refinery 2 has heavily treated their FCCU feed to the low 10 ppmv level, installing a wet gas 

scrubber to get to a level of 5 ppmv is not cost effective ($76 K per ton). Therefore, staff 

removed the emission reductions and costs associated with this control scenario from its proposal 

and subsequent analyses. With this refinement, the anticipated emission reductions and weighted 

average cost effectiveness from this process category are estimated as shown below. Staff hired 

Norton Engineering Consultants (NEC) to review the cost analyses conducted by ETS/AEC. 

The cost effectiveness estimated by using NEC recommendations is shown in Table 13-12. 

TABLE 3-12 

Comparison of Cost Effectiveness 

ETS/AEC versus NEC 

Refinery: 1 3 4 5 6 Total 

Emissions Reduction (tpd) 0.58 0.28 0.20 0.87 0.94 2.88 

Cost Effectiveness based 

on ETS/AEC ($/ton) 

$14.4k $36.6k $42.1k $11.6k $12.8k $19.6k

(Note 3)

Cost Effectiveness based 

on input from NEC ($/ton) 

$15.4k $41.3-$44.2k 

(Note 1) 

$45.1k $11.6k$

9.4k

(Note 2)

$12.8k $21.2k 

(Note 3)

Note: 1) The low end of the cost effectiveness reflects the costs of a WGS without additional PM10 control 

capability and the high end of the cost effectiveness reflects the costs of a WGS with additional PM10 control. 2) In 

March 2010, Refinery 5 revised the capital cost estimate that they provided to staff from $70 million as shown in 

their Authority for Expenditures (AFE) to $60 million dollars, and staff revised the cost-effectiveness based on the 

revised data. 3) The weighted average cost-effectiveness numbers shown here were calculated excluding the costs 

and emission reductions associated with early reductions, and excluding the costs and emission reductions 

associated with the cost-ineffective case for Refinery 2. 

The proposed BARCT is then equal to approximately 3.25 lbs/thousand barrels feed, 77%76%

reduction from the Tier I level of 13.7 lbs/thousand barrels feed. 
Final Staff Report – Part 1 Chapter 4 – Refinery Boilers and Heaters 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 47 November 2, 2010 

Chapter 4 – Refinery Boilers and Heaters 

4.1 Process Description 

Boilers and 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 4-1 provides a simplified diagram of the processes where boilers and heaters are used. 

The refinery heaters and boilers primarily use refinery gas, one of the products generated at the 

refinery. As a back-up fuel, most of these boilers and heaters use natural gas. Liquid fuel or 

solid fuel is rarely used in refinery boilers and heaters. The combustion of sulfur or sulfur 

compounds in fuel generates sulfur dioxide (SO2), with a small amount being further oxidized to 

sulfur trioxide (SO3): 

S + O2 = SO2

SO2 + 1⁄2 O2 = SO3

There are approximately 300 boilers and heaters in the refineries. The majority (96%) of these 

boilers and heaters are classified as major SOx sources. Collectively, the boilers and heaters 

emit about 3 tons per day SOx, ranging from 1 lbs to 498 lbs per day from each source, with SOx 

outlet concentration ranging from 7 ppmv – 200 ppmv. 

FIGURE 4-1 - Refinery Processes 

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 
Final Staff Report – Part 1 Chapter 4 – Refinery Boilers and Heaters 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 48 November 2, 2010 

4.2 Current Allocations and Emissions 

4.2.1 Allocations 

In 1993, all boilers and heaters at the refineries were provided allocations based on the highest 

reported fuel usage from 1987 to 1992, and an emission factor of 6.76 lbs SOx per million cubic 

foot of refinery fuel gas. This emission factor was developed based on an assumption that the 

refinery fuel gas would meet the 40 ppmv standard in Rule 431.1. 

TABLE 4-1 

SOx Allocations for Refinery Boilers/Heaters 

Facility Emission Factor 

(lbs/mmcft) 

Tier I 

Allocations (lbs/year) 

Tier I 

Allocations (tons/day) 

A 6.76 190,422 0.26 

B 6.76 139,918 0.19 

C 6.76 73,779 0.10 

D 6.76 101,839 0.14 

E 6.76 93,315 0.13 

F 6.76 49,859 0.07 

 Total 0.89 

4.2.2 Emissions 

In calendar year 2005, the refineries reported a total of 3 tons per day SOx emissions from all 

300 boilers and heaters currently operated at the refineries. Table 4-2 presents a list of the top 16 

emitters in this category which collectively emitted about 1 ton per day of SOx in 2005. 

TABLE 4-2 

SOx Emissions from Top Emitting Boilers/Heaters 

Facility Device Description Rating 

(mmbtu/hr) 

2005 

Emissions 

(tons/day)

2006 

Emissions 

(tons/day) 

2007 

Emissions 

(tons/day) 

B Crude Heater 550 0.08 0.07 0.07 

C Crude Heater 350 0.10 0.11 0.17 

C Steam Reforming Heater 340 0.09 0.06 0.1 

C Steam Generation Boiler 352 0.06 0.07 0.11 

C Steam Generation Boiler Not in operation 0.06 0.06 0.11 

C Crude Heater 154 0.04 0.04 0.07 

C Delayed Coking Unit Heater 175 0.04 0.05 0.05 

C Delayed Coking Unit Heater 175 0.04 0.07 0.06 

D Crude Heater 457 0.07 0.11 0.05 

D Hydrogen Plant Furnace 527 0.04 0.05 0.04 

D Steam Generation Boiler 291 0.03 0.02 0.02 
Final Staff Report – Part 1 Chapter 4 – Refinery Boilers and Heaters 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 49 November 2, 2010 

TABLE 4-2 (Continued) 

SOx Emissions from Top Emitting Boilers/Heaters 

Facility Device Description Rating 

(mmbtu/hr) 

2005 

Emissions 

(tons/day)

2006 

Emissions 

(tons/day) 

2007 

Emissions 

(tons/day) 

E Coking Unit Heater 252 0.07 0.06 0.06 

E Crude Distillation Heater 175 0.05 0.06 0.06 

E Delayed Coking Unit Heater 168 0.05 0.05 0.05 

E Auxiliary Boiler 139.5 0.04 0.06 0.04 

E Steam Generation Boiler 184 0.04 0.04 0.04 

Total 16 Heaters (1 Not in Operation) 0.91 0.98 1.11 

Note: The 2005 SOx emissions were from SCAQMD database for the period from January 2005 – December 2005. 

The 2006 and 2007 emissions were reported by the facilities through a Survey Questionnaire distributed by 

SCAQMD in 2008. 

As part of the responses to the 2008 SCAQMD Survey, the refineries reported that the refinery 

fuel gas is generally hydrotreated with Amine solution to reduce sulfur before being combusted 

in the refinery heaters and boilers. The sulfur contents in the refinery fuel gas were reported to 

be in a range of 49 ppmv – 327 ppmv. The SOx concentrations in in the boilers/heaters’ stacks 

vary from 6.5 ppmv – 44 ppmv 

4.3 Control Technology 

Generally, SOx emissions from boilers and heaters can be further reduced by: 

─ Using lower sulfur fuels; 

─ Improving efficiency of fuel gas treating system; and 

─ Using dry or wet gas scrubbers. 

4.3.1 Lower Sulfur Fuels 

Currently, many boilers and heaters in the U.S. still use solid fuel or liquid fuel. Solid fuel and 

liquid fuel typically contain higher sulfur content than refinery fuel gas or natural gas, thus the 

combustion of solid fuel and liquid fuel generates more NOx and SOx than other types of fuel. 

Recently, the U.S. EPA has reached various settlement agreements with the refineries to 

eliminate, or minimize, the use of solid fuel/liquid fuel in all boilers and heaters operated at the 

refineries.20, 21 According to these settlement agreements, the use of liquid/solid fuels is only 

allowed during natural gas curtailment periods. 

 

20 Motiva Enterprises LLC, Equilon Enterprises LLC, and Deer Park Refining Limited Partnership Civil Judicial 

Settlement, March 21, 2001. 

21 BP Exploration & Oil Co., Amoco Oil Comapany, and Atlantic Richfield Company Consent Decree, Civil No. 

2:96CV095RL 
Final Staff Report – Part 1 Chapter 4 – Refinery Boilers and Heaters 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 50 November 2, 2010 

In the District, boilers/heaters at the refineries typically use refinery gas as primary fuel, and 

natural gas as a back-up fuel. Liquid fuel, such as diesel, is typically used in internal combustion 

engines. Diesel fuel, if used, must contain less than 15 ppmw (0.0015%) of sulfur to comply 

with the South Coast AQMD Rule 431.2.22 This requirement is applicable to all non-RECLAIM 

facilities, as well as RECLAIM facilities, on and after June 1, 2004; however it has not been 

used to adjust the RECLAIM SOx allocations provided in 1993. 

However, it should be noted that the allocations provided for the combustion of diesel/liquid fuel 

in 1993 were approximately 0.043 tons per day, which was less than 0.5% of the total allocations 

provided to RECLAIM facilities at that time. In addition, the 2005 emissions from the 

combustion of diesel/liquid fuel in internal combustion engines are only 729 lbs per year (or 

0.001 tons per day) which is only about 0.03% of the total emissions from boilers/heaters that 

use refinery gas. Because the allocations and the 2005 emissions from the combustion 

solid/liquid fuel in refineries are negligible compared to those generated from the combustion of 

refinery gas, staff has chosen not to focus in adjusting the allocations of RECLAIM refineries 

based on the fact that they are required to comply with low sulfur diesel fuel by 2004 at this 

time. 

4.3.2 Improving Efficiency of Fuel Gas Treating System 

At the refinery, refinery fuel gas is treated in various acid gas processing units such as an amine 

or Merox treating unit for removal of sour components (e.g. hydrogen sulfide, carbonyl sulfide, 

mercaptan, ammonia). Lean amine is generally used as absorbent. At the end of the process, the 

lean amine is regenerated to form rich amine, and H2S is evolved as acid gas which is then fed to 

the SRUs/tail gas treatment as discussed in Chapter 5. By improving the efficiency of the amine 

treating unit to recover more sulfur from the inlet acid gas stream, the sulfur content of the outlet 

refinery fuel gas, and subsequently the SOx emissions from boilers and heaters that use these 

refinery fuel gases can be reduced. 

The South Coast AQMD Rule 431.1 limits the sulfur content in the refinery fuel gas to 40 ppmv 

sulfur.23 This limit was already incorporated in the RECLAIM allocations and resulted in an 

emission factor of 6.76 lbs SOx per million cubic feet of refinery gas. However, as shown in 

Table 4-3, the sulfur content in refinery fuel gas may be further reduced to 25 - 35 ppmv at some 

refineries in the U.S. The outlet SOx concentrations from boilers/heaters may also be limited to 

less than 20 ppmv. The costs of modifying an acid gas processing unit may vary widely on a 

case-by-case basis, therefore staff has chosen not to analyze this control option at this time, and 

may need to discuss this control option in details with the refineries at a later date. 

 

22 SCAQMD Rule 431.2 – Sulfur Contents of Liquid Fuels, Amended September 15, 2000. 

23 SCAQMD Rule 431.1 – Sulfur Contents of Gaseous Fuels, Amended June 12, 1998. 
Final Staff Report – Part 1 Chapter 4 – Refinery Boilers and Heaters 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 51 November 2, 2010 

TABLE 4-3 

Standards for Boilers and Heaters 

Company Description of Boilers/Heaters SOx Standard 

Marathon 

Petroleum Co 

LLC., 

Garyville 

Refinery, 

Louisiana (1)

Crude heaters, 368 mmbtu/hr 

Hydrogen reformer heater, 1412 mmbtu/hr 

Platformer heaters, 474 mmbtu/hr & 542 mmbtu/hr 

Vacuum tower heaters, 155 mmbtu/hr 

Naptha hydrotreater charge heater, 75.7 mmbtu/hr 

Naphtha hydrotreater reboiler heater, 138 mmbtu/hr 

Boiler, 526 mmbtu/hr 

Inlet standard: 25 ppmv as H2S, 

inlet concentration of refinery fuel 

gas, annual average. 

Arizona Clean 

Fuels Yuma 

LLC, Yuma 

AZ. (Facility 

has not yet 

been built.) (1) 

Atmospheric crude charge heater, 346 mmbtu/hr 

Vacuum crude charge heater, 101 mmbtu/hr 

Hydrocracker charge heater, 70 mmbtu/hr 

Hydrocracker main fractionator heater, 211 mmbtu/hr 

Naphtha hydrotreater charge heater, 21 mmbtu/hr 

Catalytic reforming charge heater, 122 mmbtu/hr 

Catalytic reforming interheater #1, 192 mmbtu/hr 

Catalytic reforming interheater #2, 129 mmbtu/hr 

Catalytic reforming debutanizer reboiler, 23 mmbtu/hr 

Distillate hydrotreater charge heater, 25 mmbtu/hr 

Distillate hydrotreater splitter reboiler, 117 mmbtu/hr 

Butane dehydrogenation reactor heater, 311 mmbtu/hr 

Butane conversion isostripper reboiler, 222 mmbtu/hr 

Delayed coking charge heaters, 99 mmbtu/hr 

Inlet standard: 35 ppmv, as H2S, 

inlet concentration of refinery fuel 

gas. 

Note: 1) The U.S. Environmental Protection Agency RACT/BACT/LAER Clearinghouse. 

4.3.3 Flue Gas Scrubbers 

While the first two control options are aiming at reducing the sulfur content of fuel before it is 

combusted, flue gas scrubbing is aiming at reducing SOx emissions in the flue gas after it exits 

the boilers and heaters. Literature contains extensive information about these technologies. 24, 25

 

24 Assessment of Control Options for Petroleum Refineries in the Mid-Atlantic Region – Final Technical Support 

Document. Prepared by MACTEC Federal Programs, Inc. for the Mid-Atlantic Regional Air Management 

Association (MARAMA), January 31, 2007. 

25 Assessment of Control Technology Options for BART-Eligible Sources – Steam Electric Boilers, Industrial 

Boilers, Cement Plants, and Paper and Pulp Facilities. Northeast States for Coordinated Air Use Management 

(NESCAUM) in partnership with the Mid-Atlantic Northeast Visibility Union (MANE-VU), March 2005. 
Final Staff Report – Part 1 Chapter 4 – Refinery Boilers and Heaters 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 52 November 2, 2010 

4.3.3.1 Dry Scrubbers 

Dry scrubbers include 1) spray dryer scrubbers and 2) dry injection scrubbers. In dry scrubbers, 

a dry calcium and sodium based alkaline powered sorbent is used to absorb SO2. A spray dryer 

scrubber refers to a configuration where the reaction between SO2 and the dry sorbent takes place 

in a dedicated reactor (or scrubber), whereas in the dry injection scrubber, the sorbent is injected 

directly into the existing boiler/heater or the ducting system of the boiler/heater. 

In the dry scrubbers, high temperatures (1800 – 2000 degree F) are needed to decompose the 

sorbent into porous solids with high adsorbing surface area. Several injection ports may be 

required for even distribution of dry sorbent in the boilers/heaters or ductwork. Cyclones and 

ESPs are typically used downstream of a dry scrubber to remove the particulate formed in the 

process. Dry injection scrubbers can achieve about 50% - 80% removal efficiency, whereas 

spray dryer scrubbers can achieve about 80% – 90%. Dry scrubbers are mostly applicable to 

small and medium size boilers/heaters with low level of inlet SOx. 

4.3.3.2 Wet Scrubbers 

In wet scrubbers, aqueous slurry of limestone, lime, or other proprietary sorbent is used to absorb 

SO2. A wet scrubber includes a spray tower which is generally followed by a mist eliminator. 

The flue gas enters a spray tower, where it is impacted with aqueous lime or limestone slurry for 

SO2 absorption. Particulate formed in the spray tower falls to the bottom of the spray tower, 

where it is collected and recycled back to the scrubber system or disposed. The scrubbed flue 

gas is then sent to a mist-eliminator to remove any entrained particulate droplets. Wet scrubbers 

are about 90% - 98% efficiency in removing SOx depending on the type of sorbent used. 

As discussed in Chapter 3, Section 3.3.2, wet scrubbers are used extensively to control SOx and 

PM from FCCUs at several refineries in the U.S. A wet scrubber designed by BELCO includes a 

spray module with two additional modules, a filtering module and a droplet separator module, to 

remove fine particulate. This scrubber has been used to achieve an outlet concentration of 25 

ppmv of SOx from FCCUs. Boilers/heaters are expected to achieve a level of 20 ppmv or lower 

as shown in Table 4-3. 

4.3.3.3 Costs and Cost Effectiveness 

Cost effectiveness for wet gas scrubbers has been estimated to be $7,700 - $45,400 per ton 

depending on the size of the scrubbers, inlet SOx, and amount of emissions reduced. 26 Using a 

wet gas scrubber may allow the refinery to combust higher sulfur fuel; and since higher sulfur 

 

26 Assessment of Control Options for Petroleum Refineries in the Mid-Atlantic Region – Final Technical Support 

Document. Prepared by MACTEC Federal Programs, Inc. for the Mid-Atlantic Regional Air Management 

Association (MARAMA), January 2007.
Final Staff Report – Part 1 Chapter 4 – Refinery Boilers and Heaters 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 53 November 2, 2010 

fuel costs less than low sulfur fuel, this can result in a savings in annual operating costs. 

BELCO estimated that using an EDV® wet gas scrubber with caustic soda (NaOH) as a 

scrubbing agent for a 198 mmbtu/hr vacuum distillation process heater burning high sulfur fuel 

of 150 ppmv – 200 ppmv could generate a saving of $1 - $2.8 million dollars per year.27 

TABLE 4-4 

Cost Effectiveness for Wet Scrubbers 

Efficiency Cost Effectiveness 

90-99.9% $7,700 - $45,400 per ton 

99%+ $1 - $2.8 million dollars annual savings for a 198 mmbtu/hr heater 

4.4 Proposed BARCT Level and Emission Reductions 

For refinery boilers/heaters, the consultants studied the technologies for pre-treatment of fuel gas 

prior to combustion, as well as the technologies for post-treatment of flue gas after combustion. 

Regarding the pre-treatment of fuel gas prior to combustion, the consultants recommended that 

the Tier I BARCT of 40 ppmv total sulfur in refinery fuel gas be retained as BARCT. Regarding 

the post-treatment of flue gas from boilers/heaters after combustion, the consultants found that 

the wet gas scrubbers were not cost-effective. Nonetheless, the consultants found that the fuel 

gas at some refineries can be further reduced to the Tier I BARCT which results in about 0.89 

tons per day emission reductions from the 2005 baseline. Staff concurred with the consultants’ 

recommendation on keeping BARCT at 40 ppmv. 

 

27 Controlling Fired Process Heater Emissions to Reduce Fuel Costs and Improve Air Quality, S.T. Eagleson and 

N. Confuorto of BELCO, S.Singhania and N. Singhania of Singhania Technical Services Pvt., and R. John of Lisha 

Engineering Co., Presented in the Petrotech 7th International Oil & Gas Conference, January 24, 2007 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 54 November 2, 2010 

Chapter 5 – Sulfur Recovery – Tail Gas Units 

5.1 Process Description 

A typical sulfur recovery system at the refineries include a sulfur recovery unit (Claus unit) 

followed by a tail gas treatment unit (e.g. Amine treating) to maximize the removal of H2S. 

The Claus sulfur recovery unit, as shown in Figure 5-1, consists of a reactor, converters and 

condensers. The two reactions proceed in the Claus sulfur recovery unit are exothermic. The 

first reaction occurs in the Claus reactor, where a portion of H2S reacts with air to form SO2. 

2H2S + 2O2 → SO2 + S + 2H20 

The second reaction takes place in the catalytic converter where SO2 reacts with H2S to form 

liquid elemental sulfur. 

2H2S + SO2 → 3S + 2H20 

Side reactions also occur which produce carbonyl sulfide (COS) and carbon disulfide (CS2), 

which have presented problems in many Claus plant operations due to the fact that they cannot 

be easily converted to elemental sulfur and carbon dioxide, 

Liquid sulfur is recovered after the final condenser. Two converters and two condensers in series 

generally remove 95% of the sulfur in the incoming acid gas. Some of the newer sulfur recovery 

units have three to four sets of converters and condensers. 

 

FIGURE 5-1 

Two Stage Claus Sulfur Recovery Process 

To recover the remaining sulfur compounds in the tail gas, the tail gas is sent to a tail gas 

treatment process, such as amine, diethanol amine (DEA), SCOT, Wellman-Lord, and 

FLEXSORB. 

First 

Converter 

First 

Condenser 

Second 

Converter 

Second 

Condenser 

Reactor

Tail Gas 

Acid Gas 

Liquid Sulfur
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 55 November 2, 2010 

Figure 5-2 shows a simplified diagram of SCOT tail gas treatment process. The sulfur 

compounds in the tail gas are reduced in a catalytic reactor to H2S. The H2S is absorbed in the 

amine (or other absorbent) in the H2S absorber, steam-stripped from the absorbent solution in the 

H2S stripper, concentrated, and recycled back to the front end of the sulfur recovery unit This 

approach typically increases the overall sulfur recovery efficiency of the Claus unit to 99.8% or 

higher. However, the fresh acid gas feed rate to the sulfur recovery unit is reduced by the 

amount of recycled stream, which reduces the capacity of the sulfur recovery unit. The residual 

H2S in the treated gas from the absorber is typically vented to a thermal oxidizer where it is 

oxidized to SO2 before emitting to the atmosphere. 

FIGURE 5-2 

Tail Gas Treatment – SCOT Process

Figure 5-3 shows a simplified diagram of Wellman-Lord tail gas treatment process. The sulfur 

compounds in the tail gas are first incinerated with air to oxidize to SO2. After the incinerator, 

the tail gas enters a SO2 absorber, where the SO2 is absorbed in typically sodium sulfite 

(Na2SO3) solution to form sodium bisulfite (NaHSO3) and sodium pyrosulfate (Na2S2O5). The 

absorbent rich in SO2 is then stripped, and the SO2 is recycled back to the Claus gas. The 

residual sulfur compounds in the treated tail gas from the SO2 absorber is typically vented to a 

thermal oxidizer where it is oxidized to SO2 before emitting to the atmosphere. 

Catalytic 

Reactor 

SO2

reduced to 

H2S 

Acid Gas 

Recycled 

Back to Claus 

Unit 

Absorber

H2S 

Stripper

Claus Unit 

Off-Gas 

Thermal 

Oxidizer 

To Stack

H2S 

Absorber 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 56 November 2, 2010 

FIGURE 5-3 

Tail Gas Treatment - Wellman-Lord Process

5.2 Current Allocations and Emissions 

5.2.1 Allocations 

In 1993, the facilities were issued emission allocations for their sulfur recovery - tail gas 

treatment unit based on the highest reported emissions from 1988 – 1992. The emissions 

allocated to each unit are listed in Table 5-1. The total Tier I allocations provided were 1.61 tons 

per day. 

TABLE 5-1 

SOx Allocations for Sulfur Recovery -Tail Gas Treatment Units 

Facility Process Peak Year 

Tier I Allocations 

(lbs/year) 

Tier I Allocations 

(tons/day) 

B Tail Gas Unit 1990 353,992 0.48 

A Inorganic Chemicals 1992 280,670 0.38 

A Sour Water Oxidizer 1992 2,328 0.00 

A Sulfur Plant 1992 65,341 0.09 

A Tail Gas Unit 1992 31,343 0.04 

D KCR Process 1992 6,904 0.01 

D Merox Process 1992 1,599 0.00 

Thermal 

Oxidizer 

Sulfur 

Cpds to 

SO2

Acid Gas 

Recycled 

Back to Claus 

Unit 

SO2

Stripper

Claus Unit 

Off-Gas 

Thermal 

Oxidizer 

To Stack

SO2

Absorber 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 57 November 2, 2010 

TABLE 5-1 (Continued) 

SOx Allocations for Sulfur Recovery -Tail Gas Treatment Units 

Facility Process Peak Year 

Tier I Allocations 

(lbs/year) 

Tier I Allocations 

(tons/day) 

D Tail Gas Unit 1992 6,008 0.01 

D Tail Gas Unit 1992 50,587 0.07 

G Tail Gas Unit 1991 14,934 0.02 

CC Sour Water Coker 1988 12,360 0.02 

CC Sour Water Oxidizer 1988 12,360 0.02 

CC Sulfur Plant 1988 87,477 0.12 

C Tail Gas Unit 1988 6,500 0.01 

E Mericher Alkyd Feed 1991 250,983 0.34 

 Total 1.61 

5.2.2 Emissions 

Since sulfur recovery - tail gas treatment unit with thermal oxidizers are classified as major 

sources in RECLAIM, the SOx emissions from these units are monitored with CEMS and 

reported on a daily basis to the District. The total annual emissions for 2005, 2006, and 2007, 

0.96 tpd, 1.02 tpd and 0.96 tpd respectively from these units are presented in Table 5-2. 

The sulfur recovery - tail gas treatment units at RECLAIM facilities are not subject to any 

specific concentration or emission rate standards. RECLAIM facilities are given the flexibilities 

to operate their equipment anyway they want provided that the total emissions from the facility 

are below facility emission caps. The allocations provided to these units since 1993 have not 

been adjusted even though there may have emerging technologies that can be used to further 

reduce SOx emissions from these units. Comparing the allocations provided in 1993 at 1.61 tons 

per day with the 2005 reported emissions at 0.96 tons per day, it seems that the sulfur recovery - 

tail gas treatment units at RECLAIM facilities have been slightly improved since 1993 provided 

that their capacity has not been changed. 

Through the 2008 Survey, the refineries reported that their SRUs’ capacity ranges from 90 long 

tons per day – 270 long tons per day. The refineries have been using more than one Claus units 

with the technologies such as SUPERCLAUS, FLEXSORB, or WELLMAN LORD to recover 

approximately 95% - 99.99% sulfur in their SRUs and tail gas treatment. All six refineries have 

thermal oxidizers at the end of their tail gas treatment units. A refinery reported that they would 

only vent the tail gas to incinerators when needed to meet the requirement of NSPS 40 CFR Part 

60, Subpart J. The stack average SOx concentrations at the outlet of the thermal oxidizers vary 

widely from 20 ppmv at 0% O2 for Refinery E, 26 ppmv for Refinery D, 59 ppmv – 77 ppmv for 

Refinery A, 98 ppmv – 150 ppmv for Refinery B, and 98 ppmv for Refinery F 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 58 November 2, 2010 

TABLE 5-2 

SOx Emissions from Sulfur Recovery – Tail Gas Treatment Units 

Facility Device Description Rating 

(mmbtu/hr) 

2005 

Emissions 

(tons/day) 

2006 

Emissions 

(tons/day) 

2007 

Emissions 

(tons/day) 

B Thermal oxidizer #2 44.5 0.16 0.22 0.26 

B Thermal oxidizer #1 39.5 0.15 0.12 0.11 

A Thermal oxidizer #70 58 0.10 0.14 0.12 

A Thermal oxidizer #20 30 0.09 0.09 0.08 

A Thermal oxidizer #10 30 0.06 0.08 0.06 

C Tail gas incinerator #1 19.5 0.01 0.00 0.01 

C Tail gas incinerator #2 19.5 0.01 0.02 0.01 

CC Thermal incinerator NA 0.05 0.10 0.09 

CC Thermal incinerator NA 0.02 0.01 0.02 

D Tail gas oxidizer 100 0.15 0.21 0.17 

E Incinerator for SRU 52 0.05 NA NA 

E Incinerator for SRU 45 0.02 NA NA 

F Thermal oxidizer 35.8 0.16 0.03 0.03 

 1.03 1.02 0.96 

Note: The 2005 SOx emissions were from SCAQMD database for the period from January 2005 – December 2005. 

The 2006 and 2007 emissions were reported by the facilities through a Survey Questionnaire distributed by 

SCAQMD in 2008. 

5.3 Control Technology 

The main purpose of the Claus sulfur recovery - tail gas treatment units is to recover sulfur. 

Afterwards, the treated gas is vented to a thermal oxidizer to oxidize the remaining H2S. The 

Claus sulfur recovery, tail gas treatment and thermal oxidizer systems in the District generally 

have recovery efficiency of about 95% - 99.99% to meet NSPS 40 CFR Part 60, Subpart J limit 

and SCAQMD Rule 468 limit (e.g. 250 ppmv SO2 with the use of thermal oxidizers, or 10 ppmv 

H2S without the use of thermal oxidizers). The three main strategies that can be employed to 

further reduce SO2 emissions from these units are 1) to increase the efficiency of the sulfur 

recovery unit, 2) to improve the efficiency of the tail gas treatment processes, and 3) to use a wet 

gas scrubber as an alternative for the thermal oxidizer. 

5.3.1 Increase Efficiency of the Sulfur Recovery Unit 

5.3.1.1 SELECTOX 

The SELECTOX catalyst is used in the first stage of the Claus unit to promote the oxidation of 

H2S to SO2 without the use of a flame. SELECTOX catalyst has helped to increase the 

efficiency of sulfur recovery unit from 90% to 97%. SELECTOX has been used in San Joaquin 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 59 November 2, 2010 

Refinery located in Bakersfield, California. 28 Other catalysts such as Criterion catalysts have 

been used to increase the sulfur recovery efficiency from a typical 96% - 97% to 99.8% - 99.9%. 

Testing on the tail gas unit at the Motiva Enterprises’ Port Arthur refinery demonstrated that the 

stack SO2 remained in the 22 ppmv – 28 ppmv range, which was only about 10% of the 

permitted maximum 250 ppmv required by NSPS, 40 CFR Part J. 29

5.3.1.2 SUPER-CLAUS®

The SUPERCLAUS sulfur recovery unit is similar to the Claus unit but contains three to four 

catalytic converters. The first two or three catalytic converters use the Claus catalysts, while the 

last reactor uses a selective oxidation catalyst that highly selective and oxidize H2S to sulfur. 

The efficiency of sulfur recovery is about 99%. 

5.3.2 Increase Efficiency of Tail Gas Unit 

5.3.2.1 SCOT Tail Gas Unit 

SCOT stands for Shell Claus Off-gas Treating, which is the most common tail gas treatment 

system. Tail gas from the Claus unit is contacted with hydrogen and reduced in the 

hydrotreating reactor to form H2S and water in the presence of a cobalt/molybdenum or alumina 

catalyst. The gas is then cooled and enters an amine absorber where it is contacted with 

monoethanolamine (MEA) or diethanolamine (DEA), or triethanolamine (TEA) to generate a 

rich amine stream. The rich amine stream is then desorbed in a stripper, where a lean amine 

stream is regenerated and recycled to the absorber, while and H2S gas stream is sent back to the 

Claus unit. This technology has been used by several refineries in the District as reported 

through the 2008 Survey. 

5.3.2.2 Sulfreen Tail Gas Unit 

The Sulfreen process is a catalytic tail gas process that adds two or three Sulfreen reactors to 

treat the tail gas. Alumina catalyst is used to remove additional sulfur. Activated titanium oxide 

is used to remove COS and CS2. Any remaining H2S leaves the reactors are oxidized in the final 

stage. The recovering efficiency of the Sulfreen process is 99 – 99.9%. 

5.3.2.3 Beaven Process 

The Beaven process uses quinine solution to absorb H2S in the tail gas. The absorbed H2S is 

then oxidized to form a mixture of elemental sulfur and hydroquinone. Hydroquinone is 

 

28 Sulfur Technology, Capability and Experience. WorleyParsons. 29 Catalysts for Lower Temperature Tail Gas Unit Operation. S. Massie and C. Wilson of Criterion Catalysts & 

Technologies, presented at the Brimstone Sulfur Recovery Symposium, Vail, Colorado, September 2005. 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 60 November 2, 2010 

converted back to quinone. Before entering the absorber, COS and CS2 in the tail gas can also 

be eliminated by the use of cobalt molybdate catalyst in a reactor located prior to the absorber. 

The recovering efficiency of the Beaven process is 99% – 99.9%. 

5.3.2.4 Stretford Process 

The Stretford process uses a hydrotreating reactor to convert SO2 in the tail gas to H2S, and then 

contacts H2S with Stretford solution in a liquid-gas absorber. The Stretford solution contains a 

mixture of vanadium salt, anthraquinone disulfonic acid (ADA), sodium carbonate, and sodium 

hydroxide. The vanadium salt acts as a catalyst to convert H2S into elemental sulfur. The 

recovering efficiency of the Stretford process is about 99%. 

5.3.2.5 FLEXSORB ® 

The FLEXSORB process were developed by the ExxonMobil Research and Engineering as 

alternative to the MDEA amine treatment process. The process uses a number of FLEXSORB 

solvents include the SE, SE Plus, SE hybrid, and the PS solvents. The solvents are designed to 

selectively absorb and convert H2S, organic sulfur to elemental sulfur. The efficiency of 

FLEXSORB is about 99.9+%. This technology has been used by one refinery in the District as 

reported through the 2008 SCAQMD Survey. 

5.3.2.6 PRO-Claus 

The Parsons RedOx Claus (PROClaus) unit is a dry catalytic process that contains three 

additional stages, a reduction and two oxidation stages. In a reduction stage, a highly selective 

SO2 reduction catalyst developed by Lawrence Berkeley National Laboratory is used to 

accelerate the reduction of SO2 to elemental sulfur. After this stage, the remaining H2S is 

oxidized to form elemental sulfur under the presence of a Parsons Hi-Activity selective oxidation 

catalyst, and then it is sent to a thermal oxidizer to complete the oxidation process. An overall 

sulfur recovery efficiency of all three stages is 99.5%. 

5.3.2.7 LO-CAT 

LO-CAT is a liquid redox tail gas treatment capable of recovering 99.9+% with or with the use 

of a proprietary Mobile Bed Absorber (MBA) where H2S and SO2 are absorbed into a circulating 

solution and converted to elemental sulfur in the presence of a chelated-iron catalyst. The 

solution leaving the MBA is then oxidized. Exhaust gas from the MBA is vented to the 

atmosphere and contains less than 10 ppmv H2S. 

Table 5-3 provides a summary of the processes described above. 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 61 November 2, 2010 

TABLE 5-3 

Control Efficiency of Sulfur Recovery – Tail Gas Treatment Process 

Process Efficiency 

Typical Claus with tail gas treatment and incinerators 90% - 95% (<250 ppmv) 

Selectox catalyst for Claus Unit 97% 

SUPERCLAUS® for Claus Unit 99% 

SCOT for Tail Gas Treatment 99% 

Sulfreen for Tail Gas Treatment 99% - 99.9+% 

Beaven for Tail Gas Treatment 99% - 99.9+% 

Stretford Tail Gas Treatment 99% 

FLEXSORB Tail Gas Treatment 99.9+% 

PRO-Claus Tail Gas Treatment 99.5% 

LO-CAT Tail Gas Treatment 99.9+% 

Reference: Assessment of Control Options for Petroleum Refineries in the Mid-Atlantic Region – Final Technical 

Support Document. Prepared by MACTEC Federal Programs, Inc. for the Mid-Atlantic Regional Air Management 

Association (MARAMA), January 31, 2007. 

5.3.3 Wet Gas Scrubber 

As described above, typically in the District, the tail gas from the Claus sulfur recovery unit is 

sent to an amine treatment process, which absorbs H2S, produces a concentrated H2S stream, and 

recycles the concentrated H2S stream to the front end of the SRU. The residual H2S in the 

treated gas is typically vented to a thermal oxidizer where H2S is oxidized to SO2 before 

emitting to the atmosphere. This approach typically increases the overall sulfur recovery 

efficiency of the Claus sulfur recovery unit; however has the tendency to reduce the amount of 

fresh acid gas stream that could potentially be treated by the Claus sulfur recovery unit. 

As an alternative to this process, the tail gas from the Claus unit is first oxidized to SO2. The 

SO2 is then captured by alkaline agent (e.g. sodium hydroxide caustic solution) in a wet gas 

scrubber, and the residual SO2 not captured in the scrubber is discharged to the atmosphere. 

With this approach, there is no concentrated H2S stream recycles to the front end of the SRU, 

and the overall sulfur recovery/removal efficiency is increased to 99.95%, above the efficiency 

of the current Claus SRU-Tail Gas Treatment systems in the District. 30 Two types of wet gas 

scrubbers that have been installed and used by the refineries in the U.S. are described in details 

below. 

 

30 Improving Sulfur Recovery Units, E. Juno of Sinclair Oil Corporation, S.F. Myer and C. Kulczycki of MECS, and 

N. Watts of CEntry Constructors and Engineers, Petroleum Technical Quarterly, Quarter 3 of 2006. 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 62 November 2, 2010 

5.3.3.1 DynaWave Non-Regenerative Scrubber 

Wet gas scrubbing technique is currently used at two refineries in Wyoming, the Sinclair Oil 

refinery, rated 72,000 barrels per day, and the Casper refinery, rated at 22,500 barrels per day. 

The scrubbers used at these two refineries are manufactured by DynaWave and use caustic 

(NaOH) as a scrubbing agent. 

 DynaWave scrubber can utilize other sodium based agents such as soda ash (Na2CO3), or 

calcium based agents such as lime (CaO) or limestone (CaCO3), however Sinclair Oil refinery 

and Casper refinery have selected caustic (NaOH) because: 

─ Caustic was available as a 50% solution which could be pumped directly to the scrubber 

without further dilution or mixing. Soda ash or calcium based agents are only readily 

available as a powder and they would require an installation of a reagent preparation station. 

─ The reaction between SO2 and caustic (NaOH) are relatively fast compared to the reaction of 

SO2 with calcium based reagents. The products, sodium sulfite (NaHSO3) or sodium 

bisulfite salts (Na2SO3) accumulated in the waste water stream, are soluble and can be 

further oxidized to reduce the COD in the waste stream to the level acceptable to the 

municipal wastewater treatment plant. In contrast, the products calcium sulfite (CaSO3) or 

calcium sulfate (CaSO4, aka gypsum) of the reaction between SO2 and calcium based agents 

are insoluble salts which are not easily removed from the scrubber solution. 

Using caustic solution as a scrubbing agent has helped the refineries to save on capital costs and 

annual operating costs, and improve the removal efficiency and operability of the system. 

Most DynaWave scrubbers contain two stages of scrubbing, or froth zones, in the inlet barrel, as 

shown in Figure 5-4. In the first scrubbing stage, the inlet process gas is adiabatically saturated 

or "quenched". The gas exits the first scrubbing stage at 150 – 180 degree F and passes through 

the second scrubbing stage. In the second stage, caustic liquid agent is again injected upward 

into the incoming gas. The SO2 is absorbed, and reacts with the caustic agent, forming sodium 

by products, sodium sulfite and sodium bisulfite salts. 

The reverse jet nozzles, located in the inlet barrel and used to inject the caustic reagent, is a 

proprietary piece of equipment supplied by Monsanto Enviro-Chem System (MECS) which is 

very critical to the scrubber application. A relatively large volume of scrubbing liquid is injected 

counter to the gas flow to create a froth zone. The gas collides with the liquid, forcing the liquid 

toward the wall. A standing wave, created at the point the liquid is reversed by the gas, is an 

extremely turbulent region. In this turbulent region, the gas absorption and particulate collection 

is enhanced significantly. 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 63 November 2, 2010 

If the SO2 concentration in the inlet gas stream is high, Dynaware will include a third stage 

scrubbing consisting of 2-inch diameter metal packing rings added to further increase the 

gas/liquid absorption. The liquid agent circulated to the third stage scrubbing can be turned off 

when it is not needed. 

FIGURE 5-4 

DynaWave Wet Gas Scrubber Used for Sulfur Recovery Tail Gas Treatment Unit 

After passing through the third scrubbing stage, the air stream will pass through a set of chevrons 

which are used to maximize the liquid droplet removal. Liquid droplets disengage from the gas 

stream and accumulate in the bottom of the vessel. The bottom of the vessel is also used as a 

reservoir for the scrubber solution which ensures continuous feed to the recirculation pumps. 

Sulfite salts are also oxidized to sulfates in the reservoir. In addition to DynaWave scrubber, 

particulate filters, ESPs, or mist eliminators can be used downstream of the wet scrubber to 

remove fine particulates. 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 64 November 2, 2010 

5.3.3.2 Cansolv® Regenerative Scrubber 

Development of the Cansolv technology started in 1988 and begun by Union Carbide Canada 

Ltd.. Since then, it has been used commercially to control SO2 from sulfur recovery units, 

sulfuric acid plants, cogeneration units, and power plant boilers. In California, the Cansolv 

technology has also been used to control SOx emitted from a sulfuric acid plant at an oil refinery 

since September 2002. The Cansolv scrubber also has been installed and operated since July 

2006 to control SOx from a sulfur recovery - tail gas application at BP Cherry Point refinery. 

The project was developed by Marsulex Inc. and is subject to an annual mass limit of 135 tons 

per year which can be translated to 150 ppmv SOx.31 Cansolv advertises that their regenerative 

scrubber can be designed to achieve 10 ppmv SO2. 32, 33, 34 

5.4 Performance Information 

The existing performance levels of the sulfur recovery units in the District reported by the 

facilities through the 2008 Survey are listed in Table 5-4. The SOx concentrations at the stack of 

the thermal oxidizers vary widely from 17 ppmv – 150 ppmv. 

TABLE 5-4 

Performance of SRU-Tail Gas Treatment in SCAQMD 

Facility % Sulfur Recovery SOx Level 

A 99.9%-99.99% 59 ppmv – 77 ppmv from thermal oxidizer 

B 90% 98 ppmv – 150 ppmv from thermal oxidizer 

C --- 17 ppmv – 56 ppmv from thermal oxidizer 

D 99.9% 26 ppmv from thermal oxidizer 

E 96% 20 ppmv from thermal oxidizer 

F 99.5% 98 ppmv from thermal oxidizer 

<3 ppmv H2S outlet of tail gas treatment unit 

The performance of several recent sulfur recovery units operated by the refineries located outside 

of the SCAQMD is shown in Table 5-5. The units were designed to meet 99%-99.9% sulfur 

recovery efficiency. 

 

31 According to the 2nd Round of Comments on RECLAIM SOx Shave Staff Report Part I, dated July 1, 2008, the 

unit is designed to meet less than 200 ppmv, 12-hour rolling average, which is the limit of NSPS Subpart J/Ja. The 

unit has a mass limit of 135 tons per year, which can be translated to 150 ppmv SOx. The system was started in July 

2006, was in operation for about 4 months, was shutdown due to equipment problems outside of the Cansolv 

system, and is currently not in operation.

32 Hydrocarbon Engineering Word Review, 2007. www.worldcoal.com/Hydrocarbon/HE_world_review_usa.htm 33 Integrating Cansolv® System Technology into the Sour Gas Treating/Sulfur Recovery Plant which indicated that 

Cansolv system can be designed to achieve 10 ppmv SO2. www.cansolv.com. 34 The Cansolv system process: A new paradigm for SO2 recover and recycle. J.N. Sarlis and P.M. Ravary of 

Cansolv Technologies, Inc. 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 65 November 2, 2010 

TABLE 5-5 

Performance of Sulfur Recovery – Tail Gas Treatment Unit 

Company Source SOx Standard 

Arizona Clean Fuels Yuma 

LLC, Yuma AZ (1)

SRU - Tail Gas 

(Amine) Unit - 

Sour Water Stripper

99.97% sulfur recovery efficiency 

BP, Texas City, Texas (2) SRU 99% sulfur recovery. All refinery fuel gas 

is scrubbed to remove sulfur. Significant 

reductions by routing vent streams from the 

SRU to the front end of the SRU, to recover 

additional sulfur instead of combusting 

sulfur to SO2. 

Shell Martinez, Contra Costa 

County, Bay Area (3)

SRU SCOT and tail 

gas thermal 

oxidizer 

Limit at 50 ppmv at 0% O2. Test showed 

13 ppmv SO2 and <0.1 ppmv H2S at 0% 

O2. 

Marathon Petroleum 

Garyville Refinery, 

Louisiana (1)

SRU with thermal 

oxidizers and 

oxygen enrichment 

93 ppmvd SO2 at 0% excess air, 99.9% 

sulfur recovery, 99.5% thermal oxidizer 

efficiency 

Note: 1) The U.S. Environmental Protection Agency RACT/BACT/LAER Clearinghouse; 2) BP Texas City Site – 

Texas City, Texas – 2004 Environmental Statement, June 2005; 3) CARB BACT Clearinghouse. 

Wet gas scrubbing technique is currently used at two refineries in Wyoming, the Sinclair Oil 

refinery and the Casper refinery since 2004. Results of a full scale testing at Sinclair refinery in 

November 2005 are shown in Table 5-4. The system was proven to be 99.99% in sulfur removal 

efficiency and resulted in SO2 outlet concentrations below 0.5 ppmv. In January 2005, Sinclair 

Oil Corporation decided to install a third DynaWave scrubber at its Tula refinery which has 

already started up in 2006. The most recent 6-months CEMS data provided to the District by 

the Wyoming air quality control office confirmed the achieved-in-practice performance for the 

DynaWave wet gas scrubbers at the level below 5 ppmv. 

TABLE 5-6 

Full-Scale Performance of DynaWave Non-regenerative Scrubber 

for Sulfur Recovery Unit at Sinclair Refinery 

 Run 1 Run 2 Run 3 Average 

SO2 inlet, lbs/hr 276.10 259.13 249.50 261.58 

SO2 outlet, lbs/hr 0.01 0.01 0.01 0.01 

SO2 outlet, ppmv 0.31 0.31 0.31 0.31 

SO2, % Removal 99.99 99.99 99.99 99.99 

Note: Based on EPA Source Test Method 6. The 0.31 ppmv is the lowest detection level for stack 

testing. From Improving Sulfur Recovery Units, E. Juno of Sinclair Oil Corporation, S.F. Myer and C. 

Kulczycki of MECS, and N. Watts of CEntry Constructors and Engineers, Petroleum Technical 

Quarterly, Quarter 3 of 2006. 
Final Staff Report – Part 1 Chapter 5 – Sulfur Recovery & Tail Gas Treatment 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 66 November 2, 2010 

5.5 BARCT Level and Emission Reductions 

Through the data provided to the consultants, there was one refinery regularly vented the flue gas 

to the atmosphere, and the remaining refineries treated or incinerated the tail gas from their 

SRU/TG systems. Because of this distinction in the refinery’s operations, the consultants 

divided their recommendations for SRU/TG into two areas. 

⎯ For uncombusted tail gas, the consultants recommended a BARCT level of NSPS Subpart J 

(Ja), namely 10 ppm H2S and 300 ppm reduced sulfur species (total of H2S, COS, and CS2) 

⎯ For the combusted tail gas, the consultants recommended 5 ppmv SOx @ 0% O2 as BARCT. 

The consultants indicated a level of 10 ppmv would allow a greater number of refineries to 

meet the overall BARCT level by the gas treatment methods without having to install a wet 

gas scrubber. 

TABLE 5-7 

Initial Emission Reductions and Cost Effectiveness Estimated 

by ETS/AEC for SRU/TGs 

Refinery: 1 2 3 4 5 6 Total 

Emission Reductions (tpd) 0.13*

(note 1)

0.17 0.15 0.04 0.06 0.29 0.83 

Cost Effectiveness based 

on ETS/AEC ($/ton) 

$22.4k

(note 3)

$39.0k

(note 2)

$12.9k

(note 3)

$54.7k

(note 3)

$123k

(note 2)

$36.3k

(note 2)

$37.4k

(note 4)

*Note: 1) Already met the emission reductions; 2) As shown in Table EX-1 of Module 3A ETS/AEC Final Report; 

3) As shown in Table EX-1 of Module 2 ETS/AEC Final Report; 4) As shown in the Summary Table EX-6 of 

Module 2 and Module 3A of ETS/AEC Final Report.

Staff concurred with the recommendations of the consultants on the level of proposed BARCT, 

except that staff will not require any BARCT with low cost effectiveness (>$50 K per ton). The 

emission reductions estimated by staff is as follows: 

TABLE 5-8 

Staff’s Proposed Emission Reductions and Cost Effectiveness for SRU/TGs 

Refinery: 2 3 6 Total 

Emission Reductions (tpd) 0.17 0.15 0.29 0.73 

Cost Effectiveness ($/ton) $39.0k $12.9k $36.3k $31.5k 

Cost Effectiveness based on input 

from NEC ($/ton) 

$49.6k $55.3k $41.6k $44.5k 
Final Staff Report – Part 1 Chapter 6 – Sulfuric Acid Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 67 November 2, 2010 

Chapter 6 – Sulfuric Acid Manufacturing 

6.1 Process Description 

Sulfuric acid manufacturing process, as shown in Figure 6-1, includes three basic operations. 

First, sulfur in the feedstock is oxidized and spent sulfuric acid is decomposed to sulfur dioxide 

(SO2) in a furnace: 

S + O2 = SO2 

Spent H2SO4 = H2O + 1⁄2 O2 + SO2

The sulfur dioxide is then catalytically oxidized to sulfur trioxide (SO3) in a multi-staged 

catalytic reactor (or converter). A typical catalyst used in the reactor is vanadium: 

2SO2 + O2 = 2SO3

The sulfur trioxide reacts with water in a absorbing tower to produce a strong sulfuric acid 

solution. 

SO3 + H2O = H2SO4

In a double absorption process, the SO3 gas formed from the primary converter is sent to a first 

absorber where the SO3 is removed to form H2SO4. The remaining unconverted SO2 and SO3

are directed to a second set of converter and absorber to further produce H2SO4. 

FIGURE 6-1 

 Sulfuric Acid Manufacturing Process 

The conversion to H2SO4 is always incomplete, and is affected by the number of stages in the 

catalytic converter, the type and amount of catalyst used, temperature and pressure, and the 

concentrations of the reactants, SO2 and O2. A 98% - 99% conversion to H2SO4 is typical. The 

Furnace 

150 mmbtu/hr Sulfur 

Spent H2SO4

H2S 

Waste 

Heat 

Boiler 

Water

Steam

Fuel Oil 

Natural Gas 

SO2

Absorbers with 

Mist Eliminators 

Catalytic 

Convertor 

Strong Acid 

SO3

Stack 

 215 ft H-6 ft DIA 

SO2

Acid Mist 

Products 98% - 99% H2SO4

Scrubbers 

with Mist 

Eliminators 

ESP 

ESP 
Final Staff Report – Part 1 Chapter 6 – Sulfuric Acid Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 68 November 2, 2010 

exhaust gas stream from the absorbers can be vented to ESPs, scrubbers, and mist eliminators to 

remove SO2 and acid mist prior to venting to the atmosphere. The process produces a great deal 

of heat. Steam driven compressors, waste heat boilers, and heat exchangers are utilized 

throughout the process to recover and convert the waste heat into useful energy. 

6.2 Current Allocations and Emissions 

6.2.1 Allocations 

Facility A and B are the two facilities in the District that operate a sulfuric acid manufacturing 

plants. In 1993, allocations were provided to these processes based on an emission factor 

ranging from 4 lbs/ton acid produced to 9.478 lbs/ton acid produced. The existing SCAQMD 

Rule 469 limits the SO2 concentration in effluent process gas from a sulfuric acid unit to 500 

ppmv and the mass emissions to 198.5 lbs/hr of sulfur compounds expressed as SO2; and NSPS 

requires a sulfuric acid manufacturing plant to meet an emission level of 4 lb SO2 per ton of 

100% acid produced, maximum 2 hour average. The allocations provided to these two facilities 

are shown in Table 6-1. 

TABLE 6-1 

Allocations for Sulfuric Acid Furnace/Reactor 

Facility 

Peak 

Year 

Emission Factor 

(lbs per ton acid produced) 

Allocations 

(lbs/year) 

Allocations 

(tons/day) 

A 1988 4.000 598,028 0.82 

B (Plant 1) 1987 4.380 371,139 0.51 

B (Plant 2) 1987 4.577 329,031 0.45 

B (Plant 3) 1989 9.478 549,904 0.75 

 Total 2.53 

Note: Prior to 1990, Facility B operated three sulfuric acid units that were built between the late 1920’s and late 

1950’s. In 1990, these three furnaces were replaced with a double absorption furnace to achieve 99.85% conversion 

efficiency and currently subject to EPA Consent Decree limiting the emission rate to 1.7 lbs SO2 per ton of acid 

produced. 

In addition to SO2, there is acid mist generated from the absorber of the sulfuric acid 

manufacturing process. Acid mist is generated when SO3 combines with water at temperature 

below the dew point of SO3. Acid mist is a very stable compound and usually is controlled and 

captured by mist eliminators. Sulfuric acid mist is limited to 0.15 lbs per ton acid produced 

under NSPS and 0.30 lbs per ton acid produced under SCAQMD Rule 469. 

6.2.2 Emissions 

The 2005 emissions reported from these processes are presented in Table 6-2. Facility B 

reported 1.13 tons per day and Facility A reported 0.04 tons per day. 

The two facilities also reported their 2006 and 2007 emissions through the SCAQMD Survey 

conducted in 2008, as shown in Table 6-2. The production rate of 100% sulfuric acid at Facility 

B is approximately 3 times larger than the production rate at Facility A. 
Final Staff Report – Part 1 Chapter 6 – Sulfuric Acid Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 69 November 2, 2010 

TABLE 6-2 

SO2 Emissions from Sulfuric Acid Furnace/Reactor 

Facility Device 

Description 

2005 Emissions 

(tons/day) 

2006 Emissions 

(tons/day) 

2007 Emissions 

(tons/day) 

A Reactor 0.04 (1) 0.06 0.05 

B Furnace 1.13 (2) 1.02 0.96 

 1.17 1.08 1.01 

Note: 1) The emissions are from a single absorption unit and controlled by a Cansolv scrubber, 2) The emissions are 

from a double absorption unit. 

The emissions from Facility A’s reactor are low compared to the emissions from Facility B’s 

furnace. Facility A’s single absorption unit uses a Cansolv scrubber to control their SOx 

emissions from the reactor, whereas the emission from Facility B’s double absorption unit is 

currently not controlled by scrubbers. The SOx outlet concentrations from Facility B’s furnace 

were in a range of 144 ppmv – 185 ppmv, whereas the SOx outlet concentrations from Facility 

A’s reactor were in a range of 17 ppmv – 51 ppmv. The emission rates calculated based on the 

information reported through the 2008 Survey are from 1.58 lbs/ton – 1.84 lbs/ton acid produced 

for Facility B, and 0.28 lbs/ton acid for Facility A. 

6.3 Control Technology 

6.3.1 EPA BARCT Clearinghouse 

Staff researched the U.S. EPA RACT/BACT/LAER Clearinghouse to identify the BARCT level 

for sulfuric acid manufacturing plant. A summary of the information posted on the 

Clearinghouse is presented in Table 6-3. 35 

In general, in addition to double absorption, the sulfuric acid manufacturing plants in the U.S. 

have upgraded their converters and absorbers, used cesium promoted vanadium catalysts, and 

added tail gas scrubbers to meet an emission level ranging from 0.2 lbs – 3.5 lbs SOx per ton of 

100% acid produced. 

6.3.2 Clean Air Act Settlements 

Recently in 2007, the U.S. Department of Justice and the U.S. EPA have announced several 

Clean Air Act settlements with two major sulfuric acid plants in the country to lower the SO2 

emissions from their sulfuric acid plants in the country. 

 

35 U.S. EPA RACT/ EPA RACT/BACT/LAER Clearinghouse. 
Final Staff Report – Part 1 Chapter 6 – Sulfuric Acid Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 70 November 2, 2010 

TABLE 6-3 

Emission Levels for Sulfuric Acid Manufacturing Plants (1)

Facility Source SOx Level 

Dupont, Union, 

New Jersey (New 

Construction in 

2007) 

Two identical 400 tons per day double 

absorption sulfuric acid plants that use spent 

acid, sulfur, and hydrogen sulfide as feed 

stocks. 

─ 0.2 lbs SOx per ton of 100% acid 

produced and 3 lbs/hr SOx at 3-hour 

average 

─ 0.10 lbs sulfuric acid mist per ton of 

100% acid produced. 

Dupont, El Paso, 

Texas (New 

Construction in 

2007) 

Double absorption sulfuric acid plant that 

use spent acid and hydrogen sulfide as feed 

stocks. 

─ 1 lbs SOx per ton of 100% acid produced 

at 3-hour average 

─ 0.10 lbs sulfuric acid mist per ton of 

100% acid produced. 

Dupont, New 

Castle, DE (New 

Construction in 

2005) 

Double absorption sulfuric acid plant, 550 

tons per day, that use spent acid and 

hydrogen sulfide as feed stocks. 

─ 1.35 lbs SOx per ton of 100% acid 

produced at 3-hour average 

─ 0.12 lbs sulfuric acid mist per ton of 

100% acid produced. 

General Chemical 

LLC, Augusta, 

Richmond 

Double absorption sulfuric acid plant, 1,000 

tons per day. A new soda ash scrubber was 

used to lower the standard from 4 lbs to 2.6 

lbs/ton 

─ 2.6 lbs SOx per ton of 100% acid 

produced at 3-hour average 

─ 0.08 lbs sulfuric acid mist per ton of 

100% acid produced. 

 CF Industries, 

Hillsborough, 

Florida 

Double absorption plant, 1,600 tons/day, 

uses spent acid, sulfur, and hydrogen sulfide 

as feed stocks. This plant has a two-stage 

ammonia scrubber and upgraded converters. 

The plant uses cesium catalysts to increase 

the SO2-SO3 conversion. 

─ 3.5 lbs SOx per ton of 100% acid 

produced, 99.5% conversion, and 401 

lbs/hr SOx at 3-hour avg. 

─ 0.10 lbs sulfuric acid mist per ton of 

100% acid produced, 99% control 

efficiency, and 11 lbs/hr sulfuric acid 

mist. 

CF Industries, 

Plant City, Florida 

Two 2,750 tons per day double absorption 

plants that use spent acid, sulfur, and 

hydrogen sulfide as feed stocks. The 

converters and absorbers were upgraded and 

cesium promoted vanadium catalysts were 

used to increase the SO2-SO3 conversion. 

─ 3.5 lbs SOx per ton of 100% acid 

produced, 99.5% conversion, and 401 

lbs/hr SOx at 3-hour average 

─ 0.10 lbs sulfuric acid mist per ton of 

100% acid produced, 99% control 

efficiency, and 11 lbs/hr sulfuric acid 

mist. 

US AgriChemicals Corp., 

Polk, Florida 

A 3,000 tons per day double absorption 

sulfuric acid plant with mist eliminators 

─ A 3.5 lbs SOx per ton 100% acid 

produced, and 99.9% conversion 

efficiency, and 1916 tons per year 

─ 0.12 lbs sulfuric acid mist per ton of 

100% acid produced, 99% control 

efficiency, and 65.7 tons per year sulfuric 

acid mist. 

Note: 1) EPA RACT/BACT/LAER Clearinghouse on EPA’s web page conducted in November 2007. 

─ Company #1 operates four sulfuric acid plants in Louisiana, Virginia, Ohio, and Kentucky. 

Under the recent settlements, the company has agreed to install $66 million state-of-the-art 

dual absorption control equipment in its largest plant located in Darrow, Louisiana. For the 

other three plants, the company has the option to install the $87 million additional control 

technologies or ceasing operations. All four plants have to meet the lower standards ranging 

from 1.7 lbs – 2.4 lbs SO2 per ton acid produced by March 1, 2012. When fully 
Final Staff Report – Part 1 Chapter 6 – Sulfuric Acid Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 71 November 2, 2010 

implemented, these plants will reduce SOx by an additional 90%. A summary of these 

agreements is included in Table 6-4. 36

─ Company #2 has agreed to spend approximately $50 million to upgrade air pollution control 

at their eight production plants in four states across the country to reduce SO2 emissions by 

approximately 95%. As shown in Table 6-4, the consent decree requires the installation of 

wet gas scrubbers or double absorption technology to meet the BARCT levels ranging from 

1.7 lbs – 2.5 lbs SOx per ton acid produced. 37

TABLE 6-4 

Consent Decree for Sulfuric Acid Manufacturing Plants 

Company SOx Level (lbs SO2 per ton) Compliance Date 

#1, Burnside, Darrow, Louisiana 2.4 (1) September 1, 2009 

#1, James River, Richmond, Virginia 1.5 (1) March 1, 2010 

#1, Fort Hill, North Bend, Ohio 2.2 (1)

 March 1, 2012 

#1, Wurtland, Wurtland, Kentucky 1.7 (1) March 1, 2012 

#2, Hammond, Indiana (3) 2.5 (2) Not specified 

#2, Martinez, California (4)

 2.2 (2) Not specified 

#2, Dominguez, California (3) 1.7 (2) Not specified 

#2, Bayton, Texas (4)

 2.2 (2) Not specified 

#2, Houston #8, Texas (5) 1.7 (2) Not specified 

#2, Houston #2, Texas (5) 1.8 (2) Not specified 

#2, Baton Rouge #2, Louisiana (5)

 2.2 (2) Not specified 

#2, Baton Rouge #1 Louisiana (5) 1.9 (2) Not specified 

Note: 1) the standard is a 3-hour rolling average. 2) The standard is a 365-day rolling average. Company #2 plants 

must meet 0.15 lbs/ton acid mist. 3) Double absorption plant. 4) Single absorption with ammonia scrubber. 5) 

Single absorption with caustic scrubber. 

6.4 Proposed BARCT Level and Emission Reductions 

As shown in Tables 6-3 and 6-4, the controlled emission level for sulfuric acid manufacturing 

plants has been improved significantly. The current controlled level can be as low as 0.2 lbs/ton 

– 0.3 lbs/ton. These levels could be achieved by upgrading the converters and absorbers, using 

cesium promoted vanadium catalysts, and/or adding tail gas scrubbers. 

In the District, Facility A has used Cansolv scrubber to control SOx emissions from its acid 

production plant, and achieved 0.28 lbs/ton acid produced. As a result, the emissions from its 

reactor have dropped from 0.82 tons per day in 1993 to 0.04 tons per day in 2005. By using 

Cansolv scrubber, Facility A has achieved an emission reduction of approximately (1- 

0.04/0.82)*100 = 95%. 

 

36 Civil Clean Air Act Settlements. www.usdoj.gov 37 Civil Clean Air Act Settlement, www.uepa.gov/compliance/resources/cases/civil/caa/rhodia-fcsht.html
Final Staff Report – Part 1 Chapter 6 – Sulfuric Acid Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 72 November 2, 2010 

The emissions from Facility B’s furnace are currently not vented to scrubbers.38 The SOx 

emissions from this facility’s furnace were in a range of 144 ppmv – 185 ppmv, and this furnace 

is the #1 SOx emitter in the District at 1.13 tons per day in 2005. 

The consultant’s analyses (NEXIDEA) for the feasibility and costs of control are summarized in 

Part 2 of the Staff Report, and the non-confidential portions of the analyses (NEXIDEA & NEC) 

are available for public information. After considering all feasible technologies, the consultants’ 

recommendation for BARCT level, which staff concurred with, is 10 ppmv for sulfuric acid 

plants. The consultants’ estimates are as follows: 

TABLE 6-5 

Emission Reductions and Cost Effectiveness Estimated by NEXIDEA 

and Cost Effectiveness Estimated Based on Input from NEC 

 BARCT Level Emission Reductions Cost Effectiveness 

NEXIDEA 0.14 lbs SOx/ton acid 

(10 ppmv) 

<0.03 tpd (Facility A) 

1 tpd (Facility B) 

$1.9k - $5.6k 

Average: $2.0k 

NEC 0.14 lbs SOx/ton acid 

(10 ppmv) 

<0.03 tpd (Facility A) 

1 tpd (Facility B) 

$2.83.3k - $8.8k 

Average: $3.4k 

Comparing to an average Tier I level of 3.93 lbs/ton, the proposed new BARCT of 0.14 lbs/ton 

reflects a 97% reduction from Tier I level. 

 

38 Permit condition no A72.1 in Facility B’s Facility Permit, dated September 2007. The 99.9% efficiency seems 

not correlated well with the SOx outlet concentrations recorded in the range of 144 – 185 ppmv from the furnace. 
Final Staff Report – Part 1 Chapter 7 – Container Glass Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 73 November 2, 2010 

Chapter 7 – Container Glass Melting Furnaces 

7.1 Process Description 

Owens-Brockway Glass Container Inc. is a container glass manufacturing facility located in 

Vernon. The company manufactures glass bottles, glass wares, pressed & blown glass, tempered 

glass, as well as safety glass. The manufacturing process contains four phases 1) preparation of 

raw material, 2) melting in a furnace, 3) forming, and 4) finishing. Figure 7-1 is a simplified 

diagram for a typical glass manufacturing process. 

Raw materials, which include sand, limestone, and soda ash, are crushed and mixed with cullets 

to ensure homogeneous melting. The raw materials are then conveyed to a continuous 

regenerative side-port melting furnace. As the materials enter the melting furnace through a 

feeder, they float on the top of the molten glass already in the furnace, melt, and eventually flow 

to a refiner section, and then fore hearths, forming machine, and annealing ovens. The final 

products undergo inspection, testing, packaging and storage. Any damaged or undesirable glass 

is transferred back to be used as cullets. 

FIGURE 7-1 

Container Glass Manufacturing Process 

Raw 

Materials 

Preparation 

and Mixing 

Melting Furnaces 

Side-Port with OxygenEnriched Air Staging 

Refining 

Annealing 

Ovens 

Inspection 

and Testing 

Cullet 

Crushing 

Packaging Storage and Shipping 

Forming 

Recycle Undesirable Glass 

Scrubbers 

(100ft L x 2ft 

++8in D) 

ESPs 
Final Staff Report – Part 1 Chapter 7 – Container Glass Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 74 November 2, 2010 

Sulfur oxides are generated from the decomposition of the sulfates in the raw materials and 

sulfur in the fuel. The melting furnace contributes over 99% of the total emissions from a glass 

plant. There are currently two melting furnaces at the Vernon facility, 60 mmbtu/hr furnace 

#23B (Device D147), and 100 mmbtu/hr furnace #23C (Device ID D112). Each furnace is 

limited to approximately 400 tons glass pulled per day. The SOx emissions are controlled by 

two scrubbers, of which one scrubber has a permit condition of 80% efficiency. The scrubbers 

are manufactured by PPC Industries, use sodium bi/sesquicarbonate as scrubbing agent, have two 

passes, and about 101 ft in length and 2ft 8 in diameter. The outlet flue gases from the scrubbers 

are directed to a common manifold and are vented to three dry ESPs downstream, one standby, 

for particulate emissions control. The furnaces currently have oxygen-enriched air staging (oxyfuel), a control technique that is commonly used to reduce NOx. 

7.2 Current Allocations and Emissions 

7.2.1 Allocations 

The allocations provided to the facility for their furnaces are presented in Table 7-1. These 

allocations were estimated based on SOx emission factors ranging from 2.12 lbs/ton to 3.15 

lbs/ton of glass pulled and their peak activities in 1992. The total allocations provided for the 

three furnaces were 1.01 tons per day. 

TABLE 7-1 

Allocations for Container Glass Melting Furnaces 

Equipment 

Peak 

Year 

Emission Factor 

(lbs per ton glass) 

Allocations 

(lbs/year) 

Allocations 

(tons/day) 

Furnace #1 1992 3.150 231,475 0.32 

Furnace #2 1992 2.480 269,673 0.37 

Furnace #3 1992 2.120 237,605 0.33 

 Total 1.01 

7.2.2 Emissions 

The emissions reported in 2005, 2006 and 2007 from Owens-Brockway’s furnaces are presented 

in Table 7-2. In total, the two furnaces emitted about 0.21 tons per day SOx in 2005, 0.27 tons 

per day in 2006, and 0.35 tons per day in 2007. The emissions from the two furnaces were 

vented to two scrubbers (one scrubber dedicated to each furnace); and three parallel ESPs 

(shared between two furnaces). The emissions were measured by three CEMS. The SOx outlet 

concentrations were averaged 64 ppmv for the first CEMS, 69 ppmv for the second CEMS, and 

85 ppmv for the third CEMS. In addition to Owens-Brockway, Saint-Gobains Containers Inc. 

operated a 78 mmbtu/hr glass melting furnace that emitted about 0.13 tons per day SOx in 2005, 

but this operation has ceased since then. 
Final Staff Report – Part 1 Chapter 7 – Container Glass Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 75 November 2, 2010 

TABLE 7-2 

SOx Emissions from Glass Melting Furnaces 

Facility 

SOx Avg 

Concentration

(ppmv) 

2005 

Emissions 

(tons/day) 

2006 

Emissions 

(tons/day) 

2007 

Emissions 

(tons/day) 

Owens-Brockway, A CEMS 64 0.076 0.27 0.35 

Owens-Brockway, B CEMS 69 0.084 

Owens-Brockway, C CEMS 85 0.036 

Saint-Gobain (shutdown) NA 0.128 NA NA 

 0.32 0.27 0.35 

Note: The 2005 SOx emissions were from SCAQMD database for the period from January 2005 – December 2005. 

The 2006 and 2007 emissions were reported by the facilities through a Survey Questionnaire distributed by 

SCAQMD in 2008. 

Through the 2008 Survey, Owens-Brockway reported that the two furnaces were in operating at 

> 90% maximum rated capacity from 2005-2007 and have emission rates ranging from 0.62 

lbs/ton – 1.05 lbs/ton glass pulled, as shown in Table 7-3. 

TABLE 7-3 

SOx Emission Rates from Glass Melting Furnaces 

Year SOx Emission Rates 

(Lbs/Ton of Glass Pulled) 

2005 0.62 

2006 0.80 

2007 1.05 

7.3 Control Technology 

In 2005, the U.S. Department of Justice and the U.S. EPA have reached an agreement with SaintGobain Containers, Inc. and required Saint-Gobain to install state-of-the-art pollution control at a 

cost of $6.6 million to reduce SO2 emissions from their melting furnaces. The Saint-Gobain 

plant located in Seattle Washington was permitted to a level of 1.6 lbs SOx per ton glass 

produced with the use of Tri-Mer Cloud Chamber Scrubber (CCS). 39 The installation of the 

CCS was just recently finished, and the plant started testing in mid of December 2007. The 

capital costs for the CCS at this plant were approximately $1,694,000, designed for an inlet flow 

of 40,000 acfm at 700 degree F. 40

Other Saint-Gobain facilities must meet a level of 0.8 lbs SO2 per ton of glass pulled. This 0.8 

lbs/ton is the most recent BARCT level for container glass melting furnaces and has been 

 

39 Title V Permit & Statement of Basis for Saint-Gobain Containers Inc. located in Seattle prepared by the Puget 

Sound Clean Air Agency, dated June 6, 2007. 

40 E-mail from Mr. Gerry Pade of Pudget Sound Clean Air Agency to Minh Pham, dated November 30, 2007. 
Final Staff Report – Part 1 Chapter 7 – Container Glass Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 76 November 2, 2010 

proposed by San Joaquin Valley APCD in their proposed rule 4354. 41, 42 Tri-Mer Corporation 

estimates that their technology can achieve a level as low as 0.1 lbs SO2 per ton of glass 

produced, 0.1 ppmv outlet SO2, and 99.9% control efficiency. The BARCT information for 

glass melting furnaces is summarized in Table 7-3. 

TABLE 7-3 

BARCT for Container Glass Manufacturing Plant 

Facility SOx Level 

Saint-Gobain Containers, Inc., Seattle, Washington 

(Tri-Mer Cloud Chamber Scrubber) 

Permitted at 1.6 lbs per ton glass 

produced. Source tested at 0.01 lbs 

per ton glass (1, 2, 3)

San Joaquin Valley APCD Rule 4354 0.9 lbs/ton glass produced 

Tri-Mer Cloud Chamber Scrubber 0.1 ppmv SO2 outlet 

0.1 lbs per ton glass produced 

99.9% control efficiency (4)

Note: 1) This is the permitted level of SOx from Saint-Gobain furnaces controlled by a Tri-Mer Cloud Chamber 

Scrubber which was designed to handle an exhaust flow of 40,000 acfm at 700 deg F. The furnaces are either 

operated at a) 205 tons per day capacity with an exhaust flow rate of 35,600 acfm at 350 deg F, or b) 195 tons per 

day capacity with an exhaust flow rate of 15,000 acfm at 500 F. 2) Fuel oil burning in these furnaces is limited to 

15 ppmv by weight of sulfur (0.0015%). 3) Based on the most recent source test at this facility in September 2009, 

the facility achieved an outlet SOx concentrations between 0.2 – 0.7 ppmv at 99% control efficiency which resulted 

in about 0.01 lbs SOx per ton glass. 4) Information provided by Tri-Mer Corporation based on their own source 

testing information. 

7.4 BARCT Level and Emission Reductions 

As noted earlier, Owens Brockway achieved a level of 0.62 lbs/ton in 2005, averaged 64 ppmv - 

85 ppmv SOx, with the use of dry scrubbing. Saint-Gobain Containers Inc. in Seattle 

Washington, with the use of Tri-Mer Cloud Chamber scrubber, can achieve an emission rate of 

0.01 - 0.1 lbs/ton, or an outlet concentration of 0.1 ppmv – 0.7 ppmv SOx, further emission 

reductions from container glass manufacturing is feasible. 

The consultant (ETS, Inc.)’s recommendation for BARCT is a level of 1 ppmv or below: 

TABLE 7-4 

Emission Reductions and Cost Effectiveness Estimated by ETS 

Equipment BARCT 

Level 

BARCT Emission 

Level 

Emission 

Reductions 

CostEffectiveness 

Owens-Brockway 

A, B & C CEMS 

99% control 

(≤1 ppmv) 

0.0058 lbs/ton 

glass pulled 0.19 tpd $ 5.201 K/ton 

 

41 Consent Decree for Saint-Gobain Containers, Inc. 

www.epa.gov/compliance/resources/reports/endofyear/eoy2005/2005aircasehighlights.html. 42 San Joaquin Valley APCD Rule 4354 – Glass Melting Furnaces, Proposed Amended Rule and Draft Staff Report, 

dated February 8, 2008. 
Final Staff Report – Part 1 Chapter 7 – Container Glass Manufacturing Process 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 77 November 2, 2010 

This is the only container glass facility in the basin. Because of the economic reason, staff’s 

recommendation for BARCT is 5 ppmv or below. The emission reductions and cost 

effectiveness are in Table 7-5. 

TABLE 7-5 

Staff’s Proposed Emission Reductions and Cost Effectiveness for Glass Furnace 

Equipment BARCT 

Level 

BARCT Emission 

Level 

Emission 

Reductions 

CostEffectiveness 

Owens-Brockway 

A, B & C CEMS 

95% control 

(≤5 ppmv) 

0.03 lbs/ton 

glass pulled 0.19 tpd $ 5.198 K/ton 
Final Staff Report – Part 1 Chapter 8 – Coke Calcining 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 78 November 2, 2010 

Chapter 8 – Coke Calcining 

8.1 Process Description 

Engineering of the coke facility began in 1978 by Martin-Marietta. Initial production of calcined 

coke occurred in February 1983. The company was purchased by BP Products Company in 

1985. BP produces calcined coke in two locations in the United States: Wilmington California 

and Cherry Point Washington, and two locations in Germany: Gelsenkirchen and Lingen. 

Basically, coke calcining is a process to improve the quality and value of “green coke” produced 

at a delayed coker in a refinery. At BP Wilmington, the green feed, produced by BP's nearby 

Carson Refinery, is screened and transported to the BP Wilmington Calciner 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 feet diameter x 270 ft long, is tumbled by rotation, 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, carried by 

conveyors to storage tanks, and later are 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 8-1. 

FIGURE 8-1 

Coke Calcining Process 

Air Pollution 

Control 

System 

(Afterburner 

- Dry 

Scrubber - 

Baghouse) 

Waste 

Heat 

Boiler 

Green 

Coke 

Storage 

Kiln

Cooler

Storage 

Tanks 

Turbine-Generator

Electricity 
Final Staff Report – Part 1 Chapter 8 – Coke Calcining 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 79 November 2, 2010 

BP Wilmington produces approximately 400,000 short tons per year of calcined products.43 The 

Wilmington coke calciner is limited to a maximum processing rate of 1,980 tons green coke per 

day, and is increasing to 2,400 tons of green coke per day.44 BP Wilmington is a global 

supplier of calcined coke to the aluminum industry, and fuel grade coke to the fuel, cement, 

steel, calciner, and specialty chemicals businesses. 

8.2 Current Allocations and Emissions 

8.2.1 Allocations 

As shown in Table 8-1, the allocations for BP coke calciner was estimated based on a controlled 

emission factor of 2.473 lbs SOx per ton of calcined coke and a production rate of 378,264 tons 

calcined coke. 45 The coke calciner was in compliance with SCAQMD Rule 1119 – Petroleum 

Coke Calcining Operations – Oxides of Sulfur, adopted March 2, 1979, which requires that the 

uncontrolled SOx emissions from coke calcining operations must be reduced by at least 80% by 

July 1, 1983. 

TABLE 8-1 

Allocations for BP Coke Calciner 

Peak 

Year 

Emission Factor 

(lbs per ton coke) 

Allocations 

(lbs/year) 

Allocations 

(tons/day) 

1989 2.473 935,447 1.28 

 Total 1.28 

8.2.2 Emissions 

The 2005-2007 reported emissions from BP coke calciner are presented in Table 8-2. Note that 

the 2005-2007 emissions are much less than the allocations provided to BP in 1993. 

TABLE 8-2 

SOx Emissions from BP Coke Calciner 

Device ID Rating 

(mmbtu/hr) 

2005 

Emissions 

(tons/day) 

2006 

Emissions 

(tons/day) 

2007 

Emissions 

(tons/day) 

20 120 0.35 0.62 0.55 

Total 0.35 0.62 0.55 

Note: The 2005 SOx emissions were from SCAQMD database for the period from January 2005 – December 2005. 

The 2006 and 2007 emissions were reported by the facilities through a Survey Questionnaire distributed by 

SCAQMD in 2008. 

 

43 BP Coke at Wilmington, http://coke.bp.com/tech/tech.cfm, September 2007. 44 SCAQMD Facility Permit to Operate of BP West Coast Products LLC, BP Wilmington, Draft, Version September 

2007. 

45 SCAQMD Tier I Emission Rate, RECLAIM, 2002
Final Staff Report – Part 1 Chapter 8 – Coke Calcining 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 80 November 2, 2010 

8.3 Control Technology 

8.3.1 Dry Scrubber at BP Wilmington 

Dry scrubbing is the chosen control technology for the BP Wilmington coke calciner. The 

control system includes a spray dryer, a reverse-air baghouse, a slurry storage system, a slurry 

circulating system, and a pneumatic conveying system. Calcium hydroxide (CaOH) slurry is the 

absorbing medium for SO2 control. Figure 8-2 shows a simplified process diagram for the dry 

scrubber system at BP Wilmington.. 

FIGURE 8-2 

Dry FGD System for Coke Calciner at BP Wilmington 

The system was designed and guaranteed to achieve 90% control efficiency for SOx at a calcined 

coke capacity of 54 tons/hour (1,296 tons/day or 473,040 tons/year). The SOx emission rates 

were tested in July 1983 to provide verification of guarantees. Production rate during the tests 

averaged 50 tons per hour and the emission rates ranged from 0.21 lbs/ton – 1.64 lbs/ton, 

averaged at 1 lbs/ton coke.46 It should be noted that the Tier I controlled emission level of SOx 

from the calciner provided in 1993 is 2.47 lbs/ton coke, even though the system was designed 

and tested to meet lower levels than 2.47 lbs/ton. 

A recent source test conducted at BP Wilmington calciner kiln reported a level of approximately 

66 ppmv SOx at a processing rate of 1,848 tons green coke per day. The processing rate was 

substantially higher than the processing rate used for the original design at 1,296 tons per day to 

achieve 90% efficient.47

 

46 Performance of Dry Flue Gas Desulfurization on a Petroleum Coke Kiln Application, R.J. Horn of Ecolaire 

Environmental Company and J.F. Bent of Martin Marietta Aluminum, Journal of the Air Pollution Control 

Association, September 1984. 

47 SCAQMD Source Test Report, R01032. 

Reactor 

Dry 

Scrubber 

Fabric 

Filter 

Slurry Tank 

Water Tank 

Slurry

Treated Gas 

at 180 deg F 

Cold Stack 

Flue Gas In (405 deg F) 
Final Staff Report – Part 1 Chapter 8 – Coke Calcining 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 81 November 2, 2010 

In responding to the 2008 Survey, BP indicated that the performance of the dry scrubber in 2005-

2007 exceeded the design levels. The control efficiencies for the dry scrubber in 2005-2007 

were in a range of 98% - 99%. The averages of SOx outlet concentrations in 2005-2007 were in 

a range of 27 ppmv – 43 ppmv, with some RATA tests conducted in 2006 and 2007 showed a 

higher level at 82 ppmv at 4% O2 and 84 ppmv at 5% O2. BP reported that with the dry 

scrubber, their emission rates in 2005-2007 were in a range of 0.56 – 0.89 lbs SOx per ton coke. 

Table 8-3 shows a comparison between design parameters and current performance in 2005-

2007. 

TABLE 8-3 

Design Parameters and Current Performance of 

Dry Scrubber for BP Wilmington Coke Calciner 

Design 

Parameter 

2005 

Performance 

2006 

Performance 

2007 

Performance 

Processing Rate (tpd) 1,296 

Control Efficiency (%) 90% 99% 98% 99% 

Emission Rate (lbs/ton) 0.21–1.64 0.56 0.97 0.89 

SOx Concentration (ppmv) Not Measured 27 ppmv 52 ppmv 43 ppmv 

8.3.2 Wet Scrubber and Wet ESP at BP Cherry Point Refinery 

In addition to the coke calciner ay Wilmington, BP operates three calciners at Cherry Point 

Refinery in Blaine, Washington. Originally, BP voluntary installed a wet scrubber to control 

SOx. Later, the company removed a portion of the wet scrubber and installed a wet electrostatic 

precipitator (WESP) to further control sulfuric acid mist emissions from the calciners, as shown 

in Figure 8-3. 

In addition, the company added a baghouse to further control PM. The calciners had an 

uncontrolled emission rate of 1125 – 1425 ppmv SOx, corrected to 7% O2. With the use of the 

wet scrubber, the SOx emissions were reduced to about 160 ppmv at 90% control efficiency. 

With the addition of a WESP, SOx emissions were reduced by 96%, and met a standard of 35 

ppmv SO2, corrected to 7% O2, on a daily average basis. The particulate fine including sulfuric 

acid mist was at 0.01 grains/dscf, corrected to 7% O2.48, 49 The performance of BP Cherry Point 

coke calciners is summarized in Table 8-4. 

 

48 Air Operating Permit - BP West Coast Products, LLC. Cherry Point Refinery Blaine, Washington, Final 

Modification. Northwest Clean Air Agency, September 06, 2006. 49 Eliminating a Sulfuric Acid Mist Plume from a Wet Caustic Scrubber on a Petroleum Coke Calciner, Charles 

Brown and Paul Hohne of VECO Pacific Inc., Environmental Progress, Vol. 20, No. 3, October 2001. 
Final Staff Report – Part 1 Chapter 8 – Coke Calcining 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 82 November 2, 2010 

FIGURE 8-3 

FGD System for Coke Calciner at BP Cherry Point 

TABLE 8-4 

Performance of Wet Scrubber and WESP 

for BP Cherry Point Coke Calciners 

Equipment: Combination of Wet Scrubber and WESP 

Processing Rate: 1,301 tons per day 

Control Efficiency: 97% - 98% 

Emission Rate: 0.14 lb SOx per ton coke 

Outlet Concentration: 35 ppmv Limit (Test Results: 10 -12 ppmv) 

8.4 BARCT Level and Emission Reductions 

Given the facts that the dry scrubber at BP Wilmington designed up to 90% efficiency could 

perform at 98% - 99% control efficiencies to achieve emission rates ranging from 0.21 lb – 1.64 

lb SOx per ton calcined coke; and that a combination of wet scrubber and wet ESP can achieve 

96% control efficiency with an emission rate of 0.14 lb SOx per ton calcined coke, staff believe 

that further emission reductions from coke calciner is possible. 

In September 2008, staff, WSPA and the refineries awarded a contract to NEXIDEA Inc. to 

conduct a feasibility and costs analysis of control technologies for coke calciner. A summary of 

the consultant (NEXIDEA)’s analysis is in Part 2 of the draft Staff Report. The consultant’s 

recommendation was 10 ppmv, which reflects 95% additional control above Tier I. Staff 

concurred with the consultant’s recommendation. After reviewing NEXIDEA’s cost analysis, 

NEC also recommended WGS as BARCT for coke calciner, however NEC’s cost-effectiveness 

was much lower as shown in table below. 

Wet 

Scrubber 

Monsanto 

Dynaware 

Wet 

ESPs 

Water

Caustic

Cold Stack 

Flue Gas from Coke Calciner 
Final Staff Report – Part 1 Chapter 8 – Coke Calcining 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 83 November 2, 2010 

TABLE 8-5 

Emission Reductions and Cost Effectiveness Estimated for Coke Calciner 

BARCT Level BARCT Emission Level Emission 

Reductions Cost-Effectiveness 

≤10 ppmv 0.11 lbs/ton calcined coke 0.28 tpd 

$ 9,902 per ton per NEXIDEA 

$23,036 per ton based on input 

from NEC 
Final Staff Report – Part 1 Chapter 9 – Portland Cement Manufacturing 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 84 November 2, 2010 

Chapter 9 – Portland Cement Manufacturing 

9.1 Process Description 

There are two Portland cement manufacturing facilities in the Basin, California Portland Cement 

Company (CPCC) and TXI Riverside Cement Company (TXI). CPCC manufactures gray 

cement, and TXI manufactures white cement and produces gray cement from clinkers delivered 

to the facility by railcar. CPCC ranks #10 on the list of top SOx emitters in the District in 2005 

with total facility emissions of 100.5 tons per year, whereas TXI is ranked #25 with total facility 

emissions of 0.7 tons per year. Therefore, staff will only focus on the technology to reduce SOx 

emissions at CPCC in this amendment. 

The production of Portland cement at CPCC is a four step process presented in Figure 9-1 which 

includes: 1) raw materials acquisition; 2) preparation of raw materials into raw mix; 3) 

pyroprocessing of raw mix to make clinkers; and 4) grinding and milling of clinkers into cement. 

Raw materials for manufacturing cement include calcium, silica, alumina and iron. Calcium is 

the element of highest concentration, and iron is raw material for gray cement but not used for 

white cement. These raw materials are obtained from minerals such as limestone for calcium; 

sand for silica; shale and clay for alumina and silica. CPCC obtains limestone from the quarry 

located on site. Other raw materials are delivered to CPCC by truck or rail car. 

Preparing the raw mix includes crushing, milling, blending and storage. Primary, secondary and 

tertiary crushers are used to crush the raw materials until they are about 3⁄4 inch or smaller in size. 

Raw materials are then conveyed to rock storage silos. Belt conveyors are typically used for this 

transport. Roller mills or ball mills are used to blend and pulverize raw materials into fine 

powder. Pneumatic conveyors are typically used to transport the fine raw mix to silos for storage 

until it is used to the pyroprocessing.. 

Pyroprocessing is the chemical and physical process of transforming the fine raw mix into 

clinkers. Pyroprocessing occurs in a rotary kiln and includes three steps: 

― Evaporating free water and dehydrating to form oxides of silicon, aluminum, and iron. This 

process occurs in a drying and preheating zone of the rotary kiln at temperatures of about 212 o

F – 800 oF; 

― Calcining of calcium carbonates (CaCO3) to form calcium oxides (CaO) and carbon dioxide 

(CO2). This process occurs in the calcining zone of the rotary kiln at temperatures of about 

1100 o

F – 1800 oF; and 
Final Staff Report – Part 1 Chapter 9 – Portland Cement Manufacturing 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 85 November 2, 2010 

― Chemical reacting, melting and restructuring of materials occur between calcium oxides 

(CaO), silica, alumina and iron to form clinker. Clinker is a solid silicate material ranges in 

size from 1 inch – 2 inch diameter, and formed in the “burning” zone of the rotary kiln at 

temperatures of about 2200 oF – 2700 oF. 

The pyroprocessing process at CPCC is called a “long dry process” consisting solely of a simple 

long rotary kiln. CPCC operates two rotary kilns in parallel, each is 18 ft in diameter and 500 ft 

in length for gray clinker. The kiln is slightly inclined and rotates on its longitudinal axis. Raw 

materials are fed into the upper end of the kiln while fuels are burned in the lower end. As the 

kiln rotates, the raw materials move slowly from the upper end to the lower end, and the 

combustion gases move in countercurrent direction. The residence time of raw materials in a 

gray cement kiln is about 2 hours – 3 hours. The hot clinker, which exits at about 2000 oF from 

the kiln, is quickly cooled in the clinker cooler and is conveyed to storage. Clinker is water 

reactive and should be protected from moisture. If clinker gets wet, it will hydrate and set into 

concrete. Heat used in the kiln is supplied through the combustion of different fuels such as 

coal, coke, oil, natural gas, and tires. The combustion gases are vented to baghouse for dust 

control, and dusts are returned to the process or recycled if they meet certain criteria, or is 

discarded to landfills. 

FIGURE 9-1 

Portland Cement Manufacturing Process at CPCC Colton 

Quarry Primary 

Secondary 

Crushers 

Rock Storage 

Crushing 

& 

Blending 

Clinker 

Storage 

Raw 

Grinding 

and 

Finish 

Grinding 

Bulk Loading 

Operations Baghouses 

Waste Heat 

Boilers & 

Turbine 

Generators 

Kilns

Clinker 

Coolers 

Fuel (Coal, Coke, Tires, Natural Gas, Oil)

Finish Products 

Gypsum 

Air 

SOx 

NOx 

ROG 

PM 

Others 

Limestone 
Final Staff Report – Part 1 Chapter 9 – Portland Cement Manufacturing 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 86 November 2, 2010 

Grinding and milling clinkers into cement is the last step of the manufacturing process. Up to 

5% of gypsum is added to the clinker during this stage to control the setting time of cement. 

Other specialty chemicals are also added. After grinding and milling, the cement is 

pneumatically conveyed to the product silos, and either sold in bulk or is bagged. 

9.2 Current Allocations and Emissions 

9.2.1 Allocations 

The allocations provided to CPCC in 1993, as well as the peak activities and emission factors, 

were presented in Table 9-1. The majority of the allocations was provided to the combustion of 

coal in boilers/heaters and cement kilns. 

TABLE 9-1 

Allocations for Kilns and Boilers at CPCC 

Equipment 

Fuel 

Type 

Peak 

Yr Emission Factor 

Emissions 

(lbs/yr) 

Emissions 

(tons/day) 

Ovens Natural Gas 1987 0.83 lbs/mmcf 101 0.00 

Boilers/Heaters Coal 1987 3.055 lbs/ton coal 217,018 0.30 

Cement Kilns Natural Gas 1987 21.45 lbs/mmcf 1,285 0.00 

Cement Kilns Fuel Oil 1987 1.08 lbs/thousand gals 12 0.00 

Cement Kilns Coal 1987 0.351 lbs/ton coal 22,569 0.03 

Cement Kilns Natural Gas 1987 7.55 lbs/mmcf 536 0.00 

Cement Kilns Fuel Oil 1987 3.07 lbs/thousand gals 384 0.00 

Cement Kilns Coal 1987 0.013 lbs/ton coal 948 0.00 

 Total 0.33 

9.2.2 Emissions 

The calendar year 2005 reported emissions from CPCC’s kilns and steam boiler are presented in 

Table 9-2. The 2005 facility emissions are still slightly below the overall allocations. However, 

the emission distribution within the facility was substantially changed: the kilns generated most 

of the facility emissions in 2005, whereas in 1987, most of the emissions originated from 

boilers/heaters at CPCC. Particulate matter from the kilns and steam boiler are controlled by 

baghouses. Limestone used in the kilns and boiler creates an alkaline environment that promotes 

a direct internal absorption of SO2. Post combustion control for SOx is not currently used at 

CPCC. 

In responding to a 2008 Survey conducted by the SCAQMD, CPCC reported that the average 

SOx concentrations from the two kilns were 49 ppmv at 13% O2 (approximately 111 ppmv at 

3% O2). The emission rate for the two kilns was approximately 0.5 lbs SOx per ton clinker.. 
Final Staff Report – Part 1 Chapter 9 – Portland Cement Manufacturing 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 87 November 2, 2010 

Regarding the coal-fired steam boiler, CPCC reported that the coal-fired steam boiler has not 

been in operation since 2002, however CPCC may operate the boiler in the near future if 

circumstances in energy costs or fuel sources change. The boiler used coal and natural gas as 

combustion fuel. The emission rate for this coal fired boiler was approximately 7 lbs SOx/ton 

coal. 

TABLE 9-2 

SOx Emissions from CPCC 

Dev 

ID 

Rating 

(mmbtu

/hr) 

SOx Level 

(ppmv) 

2005 

Emissions 

(tpd) 

2006 

Emissions 

(tpd) 

2007 

Emissions 

(tpd) 

Kiln #2 368 260 49 (13% O2) 0.193 0.146 0.186 

Kiln #1 321 260 49 (13% O2) 0.074 0.129 0.112 

Steam Boiler 851 232 NA 0.002 0.000 0.000 

 Total 0.269 0.275 0.298 

Note: The 2005 SOx emissions were from SCAQMD database for the period from January 2005 – December 2005. 

The fiscal year 2006 and 2007 emissions and the SOx concentrations were reported by the facilities through the 

2008 Survey. 

TABLE 9-3 

SOx Emission Rates 

Emission Rate 

Kilns 0.5 lbs SOx/ton clinker 

Steam Boiler 7 lbs SOx/ton coal 

9.3 Control Technology for Coal-Fired Fluidized-Bed Boilers 

9.3.1 In-Process Control Technology 

The control technologies for coal fired boilers are described abundantly in literature. 50 Almost 

all SO2 emission control technologies for coal-fired boilers are post-combustion control. The 

exception to this universal rule is found in the fluidized bed steam boiler (Device ID 851) used at 

CPCC. Fluidized bed boilers generally operate at about 1500 – 1600 degree F, a lower 

temperature regime than other combustion systems. This temperature regime allows the addition 

of limestone. Limestone (CaCO3) is converted to CaO at about 1500 degree F, and CaO 

captures SO2 to form CaSO4, which is thermodynamically stable at 1500 – 1600 degree F. A 

removal efficiency of about 90% SO2 can be achieved with a Ca/S molar ratio of 2 to 2.5, which 

also varies from application to application, and depends on the sulfur content of the fuel, 

reactivity of the limestone, and the operation of the boiler. 

 

50 Assessment of Control Technology Options for BART-Eligible Sources – Steam Electric Boilers, Industrial 

Boilers, Cement Plants, and Paper and Pulp Facilities. Northeast States for Coordinated Air Use Management 

(NESCAUM) in partnership with the Mid-Atlantic Northeast Visibility Union (MANE-VU), March 2005. 
Final Staff Report – Part 1 Chapter 9 – Portland Cement Manufacturing 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 88 November 2, 2010 

9.3.2 Dry and Wet Scrubber 

Post-combustion control for SO2 is accomplished by scrubbers. A calcium- or sodium-based 

reagent is typically used in a scrubber to absorb SO2. Sulfate or sulfite formed are either 

disposed, or further processed for commercial use. Scrubbers are commonly classified based on 

the process conditions (wet versus dry); the product utilization (throwaway versus saleable); and 

the reagent utilization (once-through versus regenerable). Scrubbers are widely used in 

commercial applications such FCCUs (Chapter 3), utility/industrial boilers/heaters (Chapter 4), 

sulfur recovery and tail gas treatment (Chapter 5), sulfuric acid manufacturing (Chapter 6), 

container glass manufacturing (Chapter 7), and coke calcining (Chapter 8). Please refer to these 

chapters for further descriptions on this technology. 

9.3.3 Costs and Cost Effectiveness Reported in Literature 

Both wet and dry scrubbers are widely used in the U.S. for coal-fired utility boilers. The control 

efficiency, costs, and cost effectiveness reported abundantly in literature are provided in Table 9-

3 and 9-4. 

TABLE 9-4 

SOx Control Technology for Boilers ≥ 250 mmbtu/hr 

Type Type of Control Control Efficiency Cost Effectiveness 

Coal Fired Dry Scrubber 90% - 95% $1,622 - $3,578 

Wet Scrubber 90% - 99% $1,881 - $3,822 

Oil Fired Dry Scrubber 90% - 95% $1,841 - $5,219 

Wet Scrubber 90% -99% $1,956 - $5,215 

Note: The data in this table are from Best Available Retrofit Technology (BARCT) for Selected Non-Electric 

Generating Units (EGU) Source Categories, MACTEC Federal Programs, Inc. developed for Lake Michigan Air 

Directors Consortium (LADCO), June 28, 2005. 

TABLE 9– 5 

SOx Control Technology for Coal-Fired Boilers 

Source Type of 

Control 

Control 

Efficiency

Capital Costs Cost Effectiveness 

Utility 

Boilers 

Dry or Wet 

Scrubber 

90% $180/kW for >600 MW units 

$350/kW for 200-300 MW 

$200 - $500 per ton 

SOx removed 

Industrial 

Boilers 

Dry Sorbent 

Injection 

40% $8,600 - $26,000 per mmbtu/hr Not Estimated 

Spray Dryer 

Absorber 

90% Double of the costs for dry 

sorbent injection 

$400 - $4000 per ton 

SOx removed 

Wet 

Scrubber 

90% 50% higher than spray dryer 

absorber 

Not Estimated 

Reference: Assessment of Control Technology Options for BART-Eligible Sources – Steam Electric Boilers, 

Industrial Boilers, Cement Plants, and Paper and Pulp Facilities. Northeast States for Coordinated Air Use 

Management (NESCAUM) in partnership with the Mid-Atlantic Northeast Visibility Union (MANE-VU), March 

2005 
Final Staff Report – Part 1 Chapter 9 – Portland Cement Manufacturing 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 89 November 2, 2010 

9.4 Control Technology for Cement Kilns 

SOx emissions from a cement kiln are generated from 1) combustion of sulfur in fuel, and 2) 

oxidation of sulfides (e.g. pyrites) in the raw materials. Fuel switching, process alterations, dry 

and wet scrubbers are commercially available control technologies to reduce SOx emissions 

from a cement kiln. 51, 52 Table 9-4 presents the control efficiency for each technology and a 

brief description for each technology is presented below. 

TABLE 9-6 

Available Control Technology for Dry Cement Kilns 

Type of Control Control Efficiency 

Fuel Switching and Process Alterations 0 – 100% 

Spray Dryer Absorber 55% - 90% 

Wet Scrubber 90% - 99.9% 

Reference: Assessment of Control Technology Options for BART-Eligible Sources – Steam Electric Boilers, 

Industrial Boilers, Cement Plants, and Paper and Pulp Facilities. Northeast States for Coordinated Air Use 

Management (NESCAUM) in partnership with the Mid-Atlantic Northeast Visibility Union (MANE-VU), 

March 2005. 

9.4.1 Fuel Switching 

Cement kilns at CPCC use coal, coke, natural gas, oil and tires as combustion fuel. When the 

fuel sulfur levels in the primary fuels are high, switching to a lower sulfur content fuel is an 

appropriate strategy. However, this strategy may not be sufficient if the fuel sulfur content is 

much less than the sulfur content of the kiln feed (e.g. limestone). In this case, staged 

combustion with mid-kiln injection of a low-sulfur fuel, or high pressure air, may need to be 

considered. A post-combustion add-on control device may also be needed to further reduce SO2 

emissions. 

9.4.2 Process Control 

The following process control can be used to reduce SOx emissions from the calciner kilns: 

─ It has been found that having sufficient oxygen to stabilize the alkali and calcium sulfate 

compounds formed in the burning zone of the rotary kiln minimizes SOx formation. The 

downside of this technique is that it can generate more NOx. 

 

51 Assessment of Control Technology Options for BART-Eligible Sources – Steam Electric Boilers, Industrial 

Boilers, Cement Plants, and Paper and Pulp Facilities. Northeast States for Coordinated Air Use Management 

(NESCAUM) in partnership with the Mid-Atlantic Northeast Visibility Union (MANE-VU), March 2005. 

52 Best Available Retrofit Technology (BARCT) for Selected Non-Electric Generating Units (EGU) Source 

Categories, MACTEC Federal Programs, Inc. developed for Lake Michigan Air Directors Consortium (LADCO), 

June 28, 2005. 
Final Staff Report – Part 1 Chapter 9 – Portland Cement Manufacturing 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 90 November 2, 2010 

─ It has been found that avoiding flame impingement in the burning zone, avoiding flame 

impingement on the clinker, or improving distribution of kiln feed to equalize temperatures 

in the kiln can minimize SO2 formation. 

─ It has been found that when alkali is in excess of sulfur, SO2 can be retained in clinker as 

alkali sulfate. In addition, reducing the amount of pyritic sulfur, or organic sulfur, in raw 

materials can lower the SOx emissions substantially. The downside of this technique is that 

the amount of alkali added, or the amount of pyretic sulfur removed, are often limited by the 

product specifications or market and economic factors. 

9.4.3 Lime or Limestone Spray Dryer Absorber 

Lime and limestone contains calcium, in the form of calcium carbonate (CaCO3), which reacts 

with SO2 and captures SO2 to form of calcium sulfate (CaSO4). Water is typically sprayed into 

the feed at the end of the kiln or introduced through dilution air at the air coolers. Two most 

common spray dryer absorbers are the RMC Pacific's Alkaline Slurry Injection System and the 

EnviroCare Microfine Lime System. The RMC Pacific uses a hydrated lime as scrubbing agent. 

The captured sulfur compounds are returned as a portion of the raw material feedstock to the 

roller mill, which results in no scrubber effluent or sludge disposal. The process has obtained 

efficiencies ranging from 55% to 65%. The EnviroCare uses water suspension of finely 

pulverized calcium hydroxide Ca(OH)2 as scrubbing agent. Lime injection rate can be 

optimized through a feedback control loop from an SO2 monitor which helps to reach a SOx 

removal efficiency of 90% or more. 

9.4.4 Wet Scrubber 

Wet scrubbing is a technique applicable to all types of cement kilns to remove SOx and 

particulate matter simultaneously. A wet scrubber is usually installed downstream of the 

baghouse and uses limestone as absorbent. The most common system is the DynaWare 

scrubber, developed by Monsanto, installed by Fuller Company, and used on several cement 

kilns in the U.S. Limestone slurry containing 20% limestone and 80% water is produced in a 

mixing tank and sprayed countercurrent to the gas flow, cools the gases, reacts with SO2 to form 

calcium sulfite (CaSO3), calcium sulfate (CaSO4), and gypsum which in turn precipitate at the 

bottom of the absorbing tower and must be disposed of. A single-stage DynaWave scrubber in 

full-scale operation has a reported SO2 removal efficiency of about 90%., and a multiple-staged 

unit may achieve 99.9% control efficiency. Please refer to Chapter 5 for further description on 

DynaWave scrubber. 

9.4.5 Costs and Cost Effectiveness 

Since wet and dry scrubbers are commonly used to further control SOx from the cement kilns, 

the costs and cost effectiveness of these technologies are abundantly available in literature, and 

are summarized in Table 9-5 and 9-6. 
Final Staff Report – Part 1 Chapter 9 – Portland Cement Manufacturing 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 91 November 2, 2010 

TABLE 9-7 

Costs for Control Technology for Dry Cement Kilns 

Source Clinker 

Capacity 

(tpy) 

Spray Dryer Wet Scrubber 

Capital Cost 

($/ton clinker)

Annual 

Operating 

Cost 

($/ton clinker) 

Capital Cost 

($/ton clinker) 

Annual 

Operating 

Cost 

($/ton clinker) 

Medium Kiln 600,000 $39.75 $14.79 $31.83 $17.21 

Large Kiln 1,200,000 $23.17 $9.43 $20.42 $13.05 

Note: (1) For comparison, CPCC Colton kiln #1 capacity is approximately 45 tons clinker per hour or 394,200 tons 

clinker per year based on a source test conducted in 2005, and an assumption that the kiln is operated 24 hours a 

day, 365 days a year. (2) The data in this table are from Assessment of Control Technology Options for BARTEligible Sources – Steam Electric Boilers, Industrial Boilers, Cement Plants, and Paper and Pulp Facilities, 

Northeast States for Coordinated Air Use Management (NESCAUM) in partnership with the Mid-Atlantic Northeast 

Visibility Union (MANE-VU), March 2005. 

TABLE 9-8 

Control Efficiency and Costs for Control Technology for Dry Cement Kilns 

Source 

Dry Scrubber Wet Scrubber 

Control 

Efficiency 

Cost Effectiveness 

($/ton SO2 removed) 

Control 

Efficiency 

Cost Effectiveness 

($/ton SO2 removed) 

Small Kiln 90%-95% $2,000 - $6,917 90%-99.99% $2,030 - $6,861 

Medium Kiln 90%-95% $1,925 - $7,379 90%-99.99% $2,004 - $6,831 

Large Kiln 90%-95% $1,881 - $7,201 90%-99.99% $1,990 - $6,816 

Reference: Best Available Retrofit Technology (BARCT) for Selected Non-Electric Generating Units (EGU) Source 

Categories, MACTEC Federal Programs, Inc. developed for Lake Michigan Air Directors Consortium (LADCO), 

June 28, 2005. 

9.5 BARCT Level and Emission Reductions 

In September 2008, staff, WSPA and the refineries awarded a contract to ETS Inc. to conduct an 

independent feasibility and costs analysis of control technologies for cement kilns and coal-fired 

boiler. A summary of ETS, Inc.’s analysis is in Part 2 of the draft Staff Report. NEC indicated 

that they would recommend WGS as BARCT for both cement kilns and coal fired boilers but did 

not provided costs information. They indicated that WGS would be more cost-effective than the 

technologies that ETS recommended. However, if the technologies recommended by ETS were 

used, NEC would recommend adding contingencies to the ETS’s estimates. The consultants’ 

recommendations are shown in Table 9-9. 
Final Staff Report – Part 1 Chapter 9 – Portland Cement Manufacturing 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 92 November 2, 2010 

TABLE 9-9 

Initial Emission Reductions and Cost Effectiveness for Kilns & 

Coal Fired Boiler Estimated by ETS, Inc. 

Equipment BARCT Level BARCT 

Emission Level 

Emission 

Reductions 

Cost Effectiveness 

by ETS 

Kilns 95% control 

(≤2 ppmv) 0.03 lbs SOx/ton clinker 0.25 tpd SOx $18.9 K per ton 

Coal-Fired 

Boiler 

95% control 

(≤5 ppmv) --- 0.36 tpd SOx $ 3.8 K per ton 

Staff concurred with the consultants’ recommendation for the coal-fired boiler, which is not in 

operation, at this time, and suggested the following BARCT level for the two cement kilns as 

shown in Table 9-10. 

TABLE 9-10 

Revised Emission Reductions and Cost Effectiveness for Cement Kilns 

Equipment BARCT 

Level 

BARCT 

Emission Level 

Emission 

Reductions Cost Effectiveness 

Kilns 5 ppmv 0.04 lbs SOx/ton 

clinker 0.25 tpd SOx 

$19.3 k per ton per ETS 

$26.8 k per ton based on input 

from NEC 
Final Staff Report – Part 1 Chapter 10 – CEMS Capability 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 93 November 2, 2010 

Chapter 10 – Continuous Emissions Monitoring System 

Staff 53 conducted an inventory of the current Continuous Emissions Monitoring Systems 

(CEMS) used at the facilities to measure SOx from the seven affected categories of sources. The 

CEMS supplier and the SOx detection range, both low and high ranges, are presented in Table 

10-1. 

TABLE 10-1

Current CEMS System 

Sources Facility CEMS Supplier SO2 Detection Range in 

ppm (High – Low) 

FCCU Refinery F Rosemount 0-250 

FCCU Refinery C Ametek 0-50 

FCCU Refinery A Bovar 0-100 

FCCU Refinery D Horiba 0-50 / 0-0.50 (diluted) 

FCCU Refinery E API 0-50 / 0-200 

FCCU Refinery B Teledyne 0-50 / 0-225 

SRU/TG Refinery F Rosemount 0-500 / 0-2000 

SRU/TG Refinery C Bovar 0-100 

SRU/TG Refinery A Bovar 0-150 / 0-1000 

SRU/TG Refinery D Rosemount 0-250 

SRU/TG Refinery E API 0-20/0-50/0-1000 

SRU/TG Refinery B Ametek 0-100 / 0-500 

Sulfuric Acid Facility Y Bovar 0-1000 

Sulfuric Acid Facility X Thermo Electron 0-200 / 0-1000 (actual); 

0-4 / 0-20 (diluted) 

Coke Calciner BP Rosemount 0-150 

Cement Cal-Portland Cement Bovar/Ametek 0-500 

Glass Owens-Brockway Thermo Electron 0-100 / 0-800 

(Data provided by AQMD Source Testing Team) 

To assure that there are systems capable of measuring low concentration levels of 5 ppmv – 40 

ppmv SOx, staff conducted a research of market availability of CEMS for low level detection. 

For detection at the lower ranges for SO2 (<10 ppm level), there are currently two main 

extractive methods for sampling the flue gas from a stack: dilution-extractive and extractive 

non-dilution. 

10.1 Dilution-Extractive 

This sample acquisition method allows for the sampling and detection of flue gas pollutants on a 

wet basis. This is convenient, since the mass emission rate is also determined on a wet basis. 

The extracted sample is diluted with clean air (typically in a 100:1 ratio) before analysis. The 

 

53 The author for Chapter 10 is Kevin Orellana. 
Final Staff Report – Part 1 Chapter 10 – CEMS Capability 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 94 November 2, 2010 

analysis is performed with an ambient SO2 analyzer, since the diluted pollutant concentration is 

near an ambient concentration level. 

10.2 Extractive Non-Dilution 

This sample acquisition method requires that the sample be clean and dry for measurement. 

Therefore, significant emphasis must be placed on particulate and moisture removal to ensure an 

accurate reading. This is often achieved by way of particulate filters and heated sample lines to 

prevent gas sample condensation. Furthermore, any remaining moisture in the sample is 

removed by way of a sample conditioning system. Usually, the technology employed involves 

refrigerated condensers, thermoelectric chillers, or gas permeation dryers. The cleaned, dry 

sample is then analyzed via an SO2 gas analyzer. 

For both sample acquisition methods, gas cleanup and sample conditioning is of foremost 

importance. For systems using dilution-extractive methods, the dilution air must be dry and free 

of contamination. For extractive non-dilution methods, the sample gas must be conditioned (free 

from particulate contamination, acid mist, ammonia, and moisture) since SO2 is soluble in water. 

The majority of the CEMS analyzers currently installed at SOx RECLAIM major sources 

employ extractive non-dilution sampling, and has the capability of monitoring in the 25ppm SO2

full span range (FSR). As expected, some upgrades may have to be performed to the existing 

systems to achieve readability in the lower ppm SO2 full span ranges. The first choice will be 

whether to install a dilution-extractive system with an ambient SO2 analyzer as a replacement for 

an extractive non-dilution system. Both dilution-extractive and extractive non-dilution systems 

can be installed in SOx RECLAIM source category equipment. However, some process-specific 

stack conditions may determine which type of system will work best at sample cleanup and 

analyte detection. 

If sample dilution is determined as the best method for SO2 detection, a completely new 

sampling system must be installed to measure pollutant gases on a wet basis approach. This will 

replace an existing extractive non-dilution system. The hardware required will consist of a 

dilution probe, sample lines, air clean up hardware, an ambient analyzer, plus integration 

hardware (cabinet, calibration hardware, programmable logic controller, and data acquisition 

system). The estimated cost for a new dilution-extractive system, including installation, is 

around $250,000. Since SO2 will be detected on a wet basis, other criteria pollutants such as 

NOx and CO may also be detected on a wet basis. New analyzers will have to be installed for 

these respective analytes in order to be sampled from the same dilution probe. 

If a facility is currently operating an extractive non-dilution system and opts to continue criteria 

pollutant measurements on a dry basis, the two essential components required for an upgrade 

would be a new SO2 gas analyzer and a gas conditioning system, such as a Nafion-based 

permeation drying system. Ametek Process Instruments, for example, manufactures an SO2 gas 

analyzer whose minimum full scale is from 0-25 ppm SO2. However, lower readings are 

possible by way of increasing the sample pressure and/or shifting to lower UV wavelengths for 

detection down to 0-10 ppm SO2 FSR. 
Final Staff Report – Part 1 Chapter 10 – CEMS Capability 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 95 November 2, 2010 

It is worth mentioning that if certain critical hardware components (e.g. probes, data acquisition 

systems, etc.) are near the end of their useful operating lives, a completely new extractive nondilution system will need to be installed. This will consist of a probe, sample lines, gas 

conditioning system, analyzer, and integration hardware. The estimated cost for a new extractive 

non-dilution system, including installation, is also around $250,000. 

However, if a facility that operates an extractive non-dilution system wants to only replace the 

SO2 analyzer and install a stack–mounted, Nafion-based, permeation drying system, the cost is 

much less: around $35,000. The operator can continue to use its existing CEMS setup until the 

end of its useful life. The heated sample lines and condensation chillers can still be retained as a 

backup to the Nafion permeation drying system. 

These above-mentioned systems have been in use at various SOx RECLAIM sources throughout 

the District. Each system uses industry-proven technology that achieves the required calibration 

results, analyte measurements, and valid Relative Accuracy Testing Audit (RATA) results. 

Due to each individual facility’s equipment setup, the CEMS shelter may or may not require 

relocation. The retrofits mentioned above are applicable to a scenario where the shelter is not 

being relocated. In this scenario, the sampling lines would be rerouted from the new SOx 

control equipment stack to the existing shelter. 

However, the unique setup of a facility may necessitate the placement of the new control 

equipment at the current location of the CEMS shelter. If the facility elects to relocate its shelter, 

a concrete pad may need to be laid at the new shelter location and utility lines may have to be 

routed there. The facility may reuse and move the existing shelter and sample lines to the new 

shelter location, or purchase brand new equipment. A new air-purged, climate-controlled, Class 

1 Division 2 shelter that can accommodate an analyzer rack costs about $250,000, and the 

facility may use general contractors or hire an engineering firm to design and manage the 

project, and the associated costs for these services may vary depending on the firm chosen. 
Final Staff Report – Part 1 Chapter 10 – CEMS Capability 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 96 November 2, 2010 

TABLE 10-2 

Future CEMS Capability 

CEMS 

Supplier 

Detection Range (ppm) What needs to be done 

to upgrade existing setup? 

Costs Per 

Unit 

Horiba 0-0.05/0-0.1/0-0.2/0-0.5 

(wet basis) 

New sampling system (dilution 

probe, sample lines, dilution air 

cleanup, analyzer, integration 

hardware) + installation 

$250,000 

Ametek 

Process 

Instruments 

0-25 (or lower, 0-10, with 

increased sample pressure and/or 

shorter UV wavelength 

detection, dry basis) 

New sampling system (probe, 

heated sample lines, gas 

conditioning system, analyzer, 

integration hardware) + 

installation 

$250,000 

Perma Pure for dry measurements Nafion-based permeation 

drying system is directly 

mounted at the stack 

$15,000 

Ametek 

Process 

Instruments 

0-25 (or lower, 0-10, with 

increased sample pressure and/or 

shorter UV wavelength 

detection, dry basis) 

Direct SO2 analyzer 

replacement at CEMS rack 

$20,000 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 97 November 2, 2010 

Chapter 11 – Water & Wastewater 

11.1 District’s Survey 

11.1.1 Water Demand 

A Survey Questionnaire shown in Appendix D was sent to the facilities in July 2009 to gather 

information on the water usage at the facilities. The facility’s responses to this Survey 

Questionnaire were summarized in Table 11-1. Staff’s assessment of the information presented 

in Table 11-1 is below: 

⎯ Total water demand is below 1 million gallons per day. As shown in Table 11-1, the increase 

in total water demand (fresh and recycled water) for this project, consisting of 11 wet gas 

scrubbers and 2 dry gas scrubbers, is estimated about 364 million gallons per year (or 1 

million gallons per day).54, 55 

⎯ Increase in total water demand. It should be noted that as shown in Table 11-1, eleven 

affected facilities currently use about 53 million gallons of water per day. The increase of 1 

million gallons of total water per day demand for this project, while meaningful, represents a 

rather modest 2% increase over the current level of total water usage at the 11 facilities.56 

⎯ Water suppliers can meet additional demand. CEQA staff has consulted the water suppliers 

for all eleven affected facilities to ask if they can support the modest 2% increase in water 

demand of this project. The water suppliers indicated to staff that they can provide the 

amount of water increase. 

 

54 Information on water demand listed in the consultants’ final report for SRU/TGTU’s wet gas scrubbers were 

incorrect. Staff used information provided directly by the wet gas scrubbers’ manufacturers as listed below. TriMer information was based on the use of caustic as a scrubbing agent. 

Water Demand Information for SRU/TG’s wet gas scrubbers Refinery 6 Refinery 3 Refinery 2 

Incorrect numbers listed in the consultants’ 

final reports MM gals/yr 614 158 342 

Draft numbers listed in the consultants’ 

draft final reports MM gals/yr 75 19 25 

Numbers provided by Tri-Mer MM gals/yr 51 26 78 

Numbers provided by DynaWave MM gals/yr 31 11 47 

Staff’s Revised Numbers MM gals/yr 51 26 78 

55 The six refineries alone would need about 264 million gallons water per year (0.7 million gallons per day) for this 

project. The six refineries currently consume 46 millions gals water per day. This project reflects a 1.5% increase 

in water demand for the refineries. 

56 Ten out of eleven facilities will have about 1% - 4% increase in water demand. Owens Brockway will experience 

a 44% increase in water demand. However, Owens Brockway has used wet gas scrubbers in the past before they 

switched to dry scrubbing technology and their water supplier (City of Vernon) indicated to staff that they can 

accommodate this increase of water demand. 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 98 November 2, 2010 

⎯ No cap on purchasing water. As shown in Table 11-1, the facilities reported that they have 

no cap in the amount of water (fresh or recycled) that they can purchase from the water 

suppliers. Some of the refineries indicated that they may have to pay an increase in water 

price in a near future because of the drought in California.57 Since the water suppliers 

indicated that they can provide the water and there is no cap on the buyers, the 2% increase 

in water demand for this project can be met by the suppliers. 

⎯ Recycled water available at major refineries. As shown in Table 11-1, of the eleven 

facilities, three refineries (Refinery #2, 3, and 6) consume the largest amount of water, 

ranging from 3,000 – 4,500 million gallons per year. These refineries however already have 

access to recycled water. Currently, 50%-90% of the water used in these major refineries is 

recycled water. The suppliers of recycled water indicated that they are working in expanding 

their capacity to supply recycled water to the facilities in the basin and can supply the water 

demand increase for this project. 

⎯ Pumping capacity remained for in-house ground water wells. As shown in Table 11-1, seven 

of the eleven affected facilities have ground water wells. All seven facilities have unused 

pumping capacity. The remaining pumping capacity is well above the increase in water 

demand at the facility due to this project. 

⎯ Potable water demand is about 96,786 gallons per day. Based on the information in Table 

11-1, two facilities (coke calciner and glass manufacturing) currently have no wells and no 

access to recycled water, and the increase in potable water demand from these two facilities 

will be about 96,786 gallons per day. The water suppliers indicated to CEQA staff that they 

can supply this increase in water demand. 

11.1.2 Wastewater 

Based on the facility’s responses shown in Table 10-2 and staff’s collected information, staff 

believes the wastewater impacts from this project would be less than significant because of the 

following reasons: 

⎯ Small increase in discharge. As shown in Table 11-2, the project would generate about 2% 

increase in wastewater (range from <1% - 11%). 

⎯ Wastewater treatment & discharge capacity available. As shown in Table 11-2, the facilities 

have available discharge capacities. Their on-site wastewater treatment plan can handle the 

small increase. In addition, since the increase in discharge is less than 25%, the facilities 

need not to revise their discharge permit. 

 

57 Regarding the price increase, a facility indicated that one of their facilities located in Northern California will 

install a wet gas scrubber as required by a U.S. EPA consent decree. The facility will pay premium price for the 

water usage above their cap, or conduct in-house program to monitor and conserve the water usage at their facility. 
Final Staff Report – Part 1 Chapter 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 99 

TABLE 11-1 – Water Demand Information 

Ref B Ref A Ref D Ref C Ref E 

FCCU MM gals/yr 28 26 18 SRUs (Revised Numbers) MM gals/yr 51 26 78Coke Calciner MM gals/yrSulfuric Acid Plant MM gals/yrGlass MM gals/yrCement MM gals/yrBoilers/Heaters (fuel gas) MM gals/yr 4 3 5 6 5 

MM gals/yr 83 55 83 6 23 

MM gals/day 0.23 0.15 0.23 0.02 0.06 

MM gals/yr 4,468 3,792 3,150 3,154 2,102 

MM gals/day 12 10 9 9 6 

Fresh water 0.05 (<1%) 1,008 (26%) 0 12% not provi

Cooling tower 1,682 (41%) 1,440 (38%) 1,100 (35%) not provided 50% 

Boiler feed 0.7 (16%) 1,344 (36%) 860 (27%) not provided 25% 

Others 2,785 (41%) 0 1.190 (38%) not provided 25% 

% Increase = (Increase in Usage / Current Usage) 2% 1% 3% 0% 1% 

Groundwater Wells 3 No well 6 2 active wells (1 at each site) 3 wells to

refinery 1 w

sulfur pl

Max Allocation for Pumping MM gals/yr

5,309 acre-ft/yr = 1,730 

MM gals/yr = 3,291 

gpm

2,570 acre-ft/yr = 837 

MM gals/yr = 1,593 

gpm

2,500 gpm

3,432 acre-f

1,118 MM ga

2,128 gp

Current Rate of Pumping MM gals/yr 1,727 acre-ft = 563 MM gals/yr = 1,071 gpm 526 MM gals/yr = 1,000 gpm Between 600 gpm - 1,800 gpm 5,000 acre-ft/

lease agree

Unused Pumping Capacity? Yes (67% remained) Yes (37% remained) Yes Yes with l

agreeme

Recycled Water Usage MM gals/yr 2,234 - 4,021 2,820 2,048 No No % Usage of Recycled Water 50% - 90% 74% 65% 0% 0% Water Supplier CWS/WBMWD WBMWD

WBMWD (65%), 

MWD (24%) and 

groundwater (11%)

CWS & LADWP LADW

Maximum Purchase Limit? No limit No limit No limit No limit No lim

CONCLUSION

No limit from water 

supplier. Groundwater is available. 

Nomimal increase of 

2% can be met. 

(note 1)

No limit from water 

supplier. Nomimal 

increase of 2% can 

be met. (note 2)

No limit from water 

supplier. Groundwater is available. 

Nomimal increase of 

2% can be met. 

No limit from water 

supplier. Ground-water 

is available. Nomimal 

increase of 2% can be 

met. 

No limit from 

supplier. G

water is ava

with lea

agreement. N

increase of 2

be me

Increase in Water Usage due to RECLAIMCurrent Water Usage (Fresh and Recycled)

MM gals/yr
Final Staff Report – Part 1 Chapter 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 100 

TABLE 11-1 – Water Demand Information (Cont.) 

BP Coke Rhodia OwensB (2 WGSs) CPCC 

FCCU MM gals/yr SRUs (Revised Numbers) MM gals/yr Coke Calciner MM gals/yr 15 Sulfuric Acid Plant MM gals/yr 7 Glass MM gals/yr 20 Cement MM gals/yr 40 Boilers/Heaters (fuel gas) MM gals/yr 

MM gals/yr 15 7 20 40 

MM gals/day 0.04 0.02 0.06 0.11 

MM gals/yr 394 266 46 1,200 

MM gals/day 1 1 0 3 

Fresh water not provided

Cooling tower 197 (50%) 226 (85%) not provided 5%

Boiler feed not provided

Others 197 (50%) 40 (15%) not provided 95%

% Increase = (Increase in Usage / Current Usage) 4% 3% 44% 3% Groundwater Wells No well 1 No well 5Max Allocation for Pumping MM gals/yr 521 acre-ft = 170 MM gals/yr No limitCurrent Rate of Pumping MM gals/yr 165 acre-ft = 54 MM gals/yr 1.9 MM gals/day

Unused Pumping Capacity? Yes. (68% remained) No limit

Recycled Water Usage MM gals/yr No No No 0% Usage of Recycled Water 0% 0% 0% 0%Water Supplier Port of Long Beach CWS City of Vernon

Riverside Highland Wate

for potable an ind water 

from wells.

Maximum Purchase Limit? No limit No limit Not reported No limit

CONCLUSION

No limit from water supplier. Nomimal 

increase of 2% can be 

met. (note 8)

Ground water is 

available and no cap 

from water supplier. 

Nomimal increase of 

2% can be met. 

(note 9)

Wet gas scrubbers are past 

practice. Percent increase 

in water is meaningful but 

can be met.

No limit on groundwater 

pumping. Nomimal 

increase of 2% can be me

Increase in Water Usage due to RECLAIMCurrent Water Usage (Fresh and Recycled)

MM gals/yr
Final Staff Report – Part 1 Chapter 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 101 

TABLE 11-1 – Water Demand Information (Cont.) Notes: 

1. Information from survey responses was submitted by the facility in August 2009. The facility indicated that there was no cap on fresh or rec

facility may have to pay a 21% increase in price of water in 2009, and may have been required to reduce water usage by 20% 2. Information from survey responses submitted by this facility on August 6, 2009. The facility indicated that there was no cap on water supply

may mandate a 20% reduction in near future. 3. - 6. Reserved 7. Based on the Survey Responses submitted on August 8 and 13, 2009, the facility indicated that they do not have a cap on water supply, howany increase to assure that there is no physical constraint (e.g. piping, pump) 8. Based on the Survey Responses submitted on August 10, 2009, the facility indicated that they do not have limits on water supplied but they 

on discharged wastewater because the fees on discharged wastewater are based on total dissolved solids and COD 9. Rhodia water information from survey responses submitted by Rhodia on August 4, 2009. CIWMB = California Integrated Waste Management Board CWS = California Water Service CRWQCB = California Regional Water Quality Control Board DTSC = Department of Toxics Substance Control LACBS = Los Angeles City Bureau of Sanitation LACSD = Los Angeles County Sanitation District 

LACDPW = Los Angeles County Department of Public Works 

LADWP= Los Angeles Department Water & Power MWD = Metropolitan Water District NPDES = National Pollutant Discharge Elimination System WBMWD= West Basin Municipal Water District 
Final Staff Report – Part 1 Chapter 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 102 

TABLE 11-2 – Wastewater Information 

Ref B Ref A Ref D Ref C Ref E 

FCCU MM gals/yr 13 12 20 8 

SRUs (Revised Numbers) MM gals/yr 10 5 16

Coke Calciner MM gals/yr

Sulfuric Acid Plant MM gals/yr

Glass MM gals/yr

Cement MM gals/yr

Boilers/Heaters (Fuel Gas) MM gals/yr 3.18 2.16 5.27 6.09 4 

MM gals/yr 27 19 21 6 12 

MM gals/d 0.07 0.05 0.06 0.02 0.03 

gpm 51 36 40 12 23 

Wastewater Treatment 

System? Yes Yes. Two systems. (note 2) Yes Yes Yes 

Wastewater Treatment 

Capacity

Capacity is limited to 8,000 gpm, normal 4,000 gpm.

1) Cap 5,000 gpm, avg 3,000 gpm. 2) Cap 2,000 gpm, avg 1,800 gpm

Cap is 3,500 gpm Normal rate is 3,000 gpm

There is a permit limit at one site which has a normal rate of 2,000 gpm. There is no limit 

Cap is 6,000 gpNormal rate is 2,215 gpm in d2,260 gpm in w

Regulator LACSD CRWQCB LACSD LACSD LACSD 

Discharge Point LACSD Santa Monica Bay LACSD LACSD & LACBS LACSD 

Discharge Limit

Hydraulically limited to 8,000 gpm & limit in wet weather is 5,200 gpm 

No limit

Limit in dry weather is 12,200 gpm & in wet weather is 7,500 gpm 

Max limit is 5,000 gpm at one site, and there is no limit at the refinery 

Max limit is 1

MM gals/d

(10,000 gpm

(Note 5)

Current Discharge 4,000 gpm 

7 MM gals/day. 

8.8 MM gals/day 

in dry weather, 27 

MM gals/day in 

wet weather 

3,000 gpm

2,000 gpm at one site 

and 1,400 gpm at the 

refinery.

2,215 gpm in 

weather and 2

gpm in wet we

Remaining Capacity = 

Discharge Limit - (Current 

Discharge + Increase)

3,649 gpm 

hydraulically & 1149 

gpm in wet weather

No limit

In dry weather = 9,160 gpm & in wet weather = 4,460 gpm

No limit at the refinery. At the other site about 3,000 gpm

7,717 gpm

% Increase=(Increase / 

Discharge Limit) <1% --- <1% 0.2% 0.2% 

CONCLUSION

Wastewater 

treatment & 

discharge capacity 

are available. No 

need to revise 

LACSD permit. 

(note 1)

Wastewater 

treatment and 

discharge 

capacity are 

available. 

(note 2)

Wastewater 

treatment and 

discharge 

capacity available.

Discharge capacity 

available. Less 

than significant 

impact.

Less than 

significant im

Increase in Discharge
Final Staff Report – Part 1 Chapter 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 103 

TABLE 11-2 – Wastewater Information (Cont.) 

BP Coke Rhodia OwensB CPCC 

FCCU MM gals/yr 

SRUs (Revised Numbers) MM gals/yr 

Coke Calciner MM gals/yr 6 

Sulfuric Acid Plant MM gals/yr 4 

Glass MM gals/yr 5 

Cement MM gals/yr 52 

Boilers/Heaters (Fuel Gas) MM gals/yr

MM gals/yr 6 4 5 52 

MM gals/d 0.02 0.01 0.01 0.14 

gpm 11 8 10 99 

Wastewater Treatment 

System?

Yes. A basin for pH 

adjustment.

Yes. On-site tanks for 

neutralization. Yes. No wastewater treatment. Percolation ponds on site.

Wastewater Treatment 

Capacity

0.18 MM gals/day 

(based on 125 gpm 

peak flow)

0.6 MM gals/day 

(425 gpm)

0.4 MM gals/day 

(250 gpm)

Regulator LACSD LACSD & LACDPW LACSD & City of Vernon California Regional Water Control Board, Santa Ana

Discharge Point LACSD LACSD LACSD On site

Discharge Limit

0.18 MM gals/day 

(based on 125 gpm 

peak flow)

0.6 MM gals/day (425 gpm) 

as shown on LACSD permit

131.4 MM gals/yr 

(0.36 MM gals/day) 

(250 gpm)

No limit

Current Discharge

0.09 MM gals/day 

(93,775 gpd or 65 gpm 

daily average)

Peak is 0.56 Mmgals /day 

(387 gpm), and average is 0.25 

MM gals/day (175 gpm)

41.89 MM gals/yr 

(0.12 MM gals/day)

0.45 MM gals/day dust slurry 

to evaporation ponds & 1.05 

MM gals/day of cooling water 

wastes to percolation ponds.

Remaining Capacity = 

Discharge Limit - (Current 

Discharge + Increase)

0.07 MM gals/day 

(=0.18-0.09-0.02)

0.03 MM gals/day 

(=0.6-0.56-0.01)

84.5 MM gals/yr 

(0.23 MM gals/day) No limit

% Increase=(Increase / 

Discharge Limit) 11% 2% 4% No limit

CONCLUSION

Discharge capacity 

available. Less than 

significant impact. 

(note 8)

Discharge capacity 

available. Peak flow must 

be carefully managed. 

(note 9)

Less than significant 

impacts

Less than significant 

impacts

Increase in Discharge
Final Staff Report – Part 1 Chapter 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 104 

TABLE 11-2 – Wastewater Information (Cont.) Notes 

1. This facility reported a maximum treated capacity of 8,000 gpm (12 million gals per day) and a normal treated rate of 4,000 gpm (6 million gals per day). S

Hanh Le to Minh Pham on August 5, 2009) provided a slightly smaller discharge levels 2. This facility has two distinct wastewater treatment systems. The first system has primary treatment only. The second system has both primary and seconda

has wastewater storage capacity to handle surges due to storms and upset 3. Reserved 4. For this refinery, see e-mail from Cynthia Carter to Minh Pham on August 5, 2009. Wilmington site has no maximum limit of discharge. LACSD indicated 

any significant impacts to their waste water treatment system 5. For this facility, see e-mail from Sawsan Andawis to Minh Pham on August 6, 2009. The facility reported that if they are over 25% baseload of waswater d

subject to a large connection fee minimum of $7.8 MM & claimed that with a wet gas scrubber installation, they will exceed the 25% baseload, which is unlike6. From the Survey Responses submitted on August 8, 2009, the facility responded that they do not have a wastewater treatment facility, and currently send altreatment. Currently, the permit given by LACSD has a cap 7. Reserved 8. Based on the Survey Responses submitted on August 10, 2009, the facility indicated that "Additional scope and cost should have been included to reduce/of

from this project....". 9. For Rhodia, based on the Survey Responses submitted on August 4, 2009, all wastewater is pumped into above ground agitated tanks and sodium hydoxide 

above 6.0. The discharge limit is 0.6 MM gals per day max (425 gals/min). 

CIWMB = California Integrated Waste Management Board CWS = California Water Service CRWQCB = California Regional Water Quality Control Board DTSC = Department of Toxics Substance Control LACBS = Los Angeles City Bureau of Sanitation LACSD = Los Angeles County Sanitation District 

LACDPW = Los Angeles County Department of Public Works 

LADWP= Los Angeles Department Water & Power MWD = Metropolitan Water District NPDES = National Pollutant Discharge Elimination System WBMWD= West Basin Municipal Water District 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 105 November 2, 2010 

11.2 California Water Plan 

The California Water Plan provides a framework for water managers, legislators, and the public 

to consider options and make decisions regarding California’s water future. The Plan, which is 

updated every five years, presents basic data and information on California’s water resources 

including water supply evaluations and assessments of agricultural, urban, and environmental 

water uses to quantify the gap between water supplies and uses. The Plan also identifies and 

evaluates existing and proposed statewide demand management and water supply projects to 

address the State’s water needs. The California Department of Water Resources (DWR) just 

recently released the 2009 California Water Plan update in February 2010.58 

The 2009 Plan focuses on strategies to use water efficiently, improve water reliability and water 

quality, and for the first time, integrate water resource management with flood management 

throughout the state. In addition, the Plan for the first time discussed the impacts of climate 

change and included the effects of climate change in estimating the water demand and supply for 

each of the ten hydrologic regions in California. The Plan includes 5 volumes: Volume 1 

describes the current water conditions in California and challenges, presents the strategic plans 

for the state as well as for the 10 hydrologic regions, and identifies recommendations that will be 

incorporated statewide in the next couple years; Volume 2 describes 27 resource management 

strategies (e.g. reduce water demand, improve operational efficiency and transfers, increase 

water supply, improve water quality, practice resources stewardship, and improve flood 

management) that can be implemented in a mix and match fashion to help the 10 hydrologic 

regions to diversify their water portfolio and become more regionally self-sufficient; Volume 3 

contains specific regional reports, and each regional report includes a water balance summary of 

water use and water supply for the region from 1998 through 2005, and scenario results that 

project the region’s water needs through year 2050 with the use of three future scenarios (i.e. 

Current Trends, Slow and Strategic Growth, and Expansive Growth)59 and 12 climate change 

scenarios; Volume 4 and Volume 5 contain references and technical information. For further 

information about the 2009 California Water Plan Update, please visit the website the California 

Department of Water Resources.60 

 

58 The 2009 California Water Plan Update, http://www.waterplan.water.ca.gov/cwpu2009/index.cfm, 

http://www.waterplan.water.ca.gov/docs/cwpu2009/0310final/highlights_cwp2009_spread.pdf

http://www.waterplan.water.ca.gov/docs/cwpu2009/0310final/v3_southcoast_cwp2009.pdf

http://www.waterplan.water.ca.gov/docs/cwpu2009/0310final/v2c11_recycmuniwtr_cwp2009.pdf

http://www.waterplan.water.ca.gov/docs/cwpu2009/0310final/v2c03_urbwtruse_cwp2009.pdf 

59 In the “Current Trends” scenario, it was assumed that the existing trends in California will continue to 2050, the 

population increases to nearly 60 million people in California in 2050, affordable housing has drawn families to the 

interior valleys, and people take longer trips in distance and time. In the “Slow and Strategic Growth” scenario, it 

was assumed that there will be more efficient planning and development, population growth is slower and projected 

to increase to 45 million people, families live in compact urban development and commute less, Californian 

embraces water and energy conservation, and state government successfully implements and coordinates program to 

improve water quality. In the “Expansive Growth” scenario, it was assumed that the population will increase to 70 

million people in 2050, Californian prefers low-density housing, some water and energy conservation was offered 

but at a slower rate than current trends. 

60 California Department Water Resources website - http://www.waterplan.water.ca.gov/ 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

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Proposed Amended Regulation XX Part I - 106 November 2, 2010 

A big picture of the current water demand and use, the predicted water demand and use for the 

next 30 years, as well as the Best Management Practices (BMP) and the strategies to conserve 

water that the DWR recommends can be found in the 2009 California Water Plan Update. Staff 

focuses its research in the South Coast Hydrologic Region. The South Coast region is the 

California’s most urbanized and populous region with the largest population of the state at 

almost 20 million. The South Coast region covers all of Orange County and portions of Ventura, 

Los Angeles, San Bernardino, Riverside and San Diego counties. The region has numerous 

sources of water supplies: imported water, surface water, groundwater, recycled water, and 

desalination. According to Metropolitan Water District of Southern California (MWD), half of 

the water supplied to the Southern California is from local supplies (e.g. groundwater wells. 

lakes) and the other half is imported water from Northern California via the State Water Projects 

(SWP) passing through the Sacramento-San Joaquin Delta (Delta), the Colorado River, and 

Owens Valley/Mono Basin. 

The State Water Project (SWP) is an important source of water for the South Coast region. The 

SWP is managed by the California Department of Water Resources (DWR). There are about 6 

major contractors for the SWP. These contractors take delivery and convey the suppliers to 

regional wholesalers and retailers. The MWD is one of the major contractors. The contract 

between MWD and DWR is approximately about 1.91 MAF per year, half of the total SWP.61 

Another key imported water supply for the South Coast region is the Colorado River. The DWR 

is entitled to 4.4 MAF per year from the Colorado River, of which 3.8 MAF are assigned to 

agricultural users and the remaining to MWD. Within the last couple years, MWD routinely 

uses 1.2 MAF from the Colorado River because the agricultural users have not been using their 

full entitlement. MWD conveys the water through a 242-mile Colorado River Aqueduct to 

supply to the retailers in Southern California. 

Another source of imported water is the water from Mono Basin and Owens Valley. 

Approximately 480,000 acre-feet per year of water is delivered by the LADWP through the Los 

Angeles Aqueduct to the City of Los Angeles. However, this amount varies from year to year 

due to fluctuating precipitation in the Sierra Nevada Mountains 

Local surface water (e.g. Lake Casitas, Lake Piru, Castaic Lake, Lake Perris) plays an important 

part in the big picture of water supply to Southern California. More than 75 impound structures 

are used to capture runoff for direct use and groundwater recharge, operational and emergency 

storage, and food protection. 

Groundwater production within the Metropolitan service area is estimated at 1.6 MAF per year. 

However, natural recharge is typically insufficient to maintain the groundwater basin water 

levels and current pumping levels due to the extent of impervious surfaces and the presence of 

clay soils. Many local water agencies must rely on artificial recharge (e.g. using recycled water). 

The Water Replenishment District of Southern California (WRD) has the mission to manage and 

protect the groundwater supply in the basin. In the past couple years, most basin adjudications 

 

61 2009 California Water Plan Update, South Coast, Volume 3 Regional Report. 
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Proposed Amended Regulation XX Part I - 107 November 2, 2010 

have resulted in either a reduction or no increase in the amount of groundwater that can be 

extracted. 

Within MWD’s service area, there are approximately 355,000 acre-feet of planned and permitted 

uses of recycled water supplies. Actual use is approximately 209,000 acre-feet, mainly in golf 

course, landscape, irrigation, industrial uses, construction applications, maintenance of seawater 

barriers, and groundwater recharge. The MWD projected a development of 500,000 acre-feet 

recycled water supplies by 2025. The use of recycled water by LADWP is projected to 

approximately 50,000 acre-feet per year by 2019. 

Besides imported water, groundwater, and local surface waters, urban water conservation and 

desalination are also the sources of water supplies in the area. Local water agencies utilize a 

mixture of local and imported waters, and implement diverse water management strategies to 

meet the urban and agricultural demands. The total water use in the South Coast Hydrologic 

Region is reported to be approximately 4.8 MAF averaged from 1998-2005 period and about 5.2 

MAF in 2005. In the 2009 California Water Plan Update, it is projected that the urban water 

demand will have a range of increase from 1.65 MAF in 2050 for the “Current Trends” scenario 

to 3.24 MAF with “Expansive Growth” scenario. The “Slow & Strategic Growth” scenario 

resulted in relative smaller increase in water demand of 0.145 MAF. 

To meet the California’s water challenges, Governor Schwarzenegger and state lawmakers have 

successfully crafted a plan that passed legislation and signed into law in November 2009. The 

plan is comprised of four policy bills (Senate Bills No. 1, 6, 7, 8) and $11.14 billion bond. 

Senate Bill No. 1 establishes the framework to provide a more reliable water supply to California 

and restore the Delta ecosystem. Senate Bill No. 6 requires, for the first time in California’s 

history, that local agencies monitor the groundwater levels during both normal water years and 

drought conditions. Senate Bill No. 7 requires urban water agencies/suppliers to reduce the 

potable water consumption by 20% per capita by 2020, and Senate Bill No. 8 requires stronger 

accounting of the location and amounts of water being diverted from the Delta and appropriates 

existing bond funds to various activities to benefit the Delta ecosystem and secure the reliability 

of the state’s water supply. In addition, the newly funded bond of $11.14 billion is approved by 

the Governor to fund drought relief, water supply reliability, Delta sustainability, statewide water 

system operational improvements, conservation and watershed protection, groundwater 

protection, and water recycling and water conservation programs. A summary of the four Senate 

Bills and bonds are provided in the 2009 California Water Plan Update.62 The focus of the next 

section is to discuss the 20x2020 Water Conservation Plan which is the backbone of information 

for the Senate Bill 7 (SBX7 7) which calls for a 20% reduction of potable water per capita by 

2020. 

 

62 The 2009 California Water Plan Update, 2009 Comprehensive Water Package – Special Session Policy Bills and 

Bond Summary. http://www.waterplan.water.ca.gov/docs/cwpu2009/0310final/v4c15a05_cwp2009.pdf. 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 108 November 2, 2010 

11.3 20x2020 Water Conservation Plan 

In February 2008, the Governor directed state agencies to develop a 20x2020 Water 

Conservation Plan that aims to reduce statewide per capita urban water use by 20 percent by the 

year 2020. In order to develop the 20x2020 Plan, an Agency Team was formed which consisted 

of state and federal agencies including the Department of Water Resources (DWR), State Water 

Resources Control Board (SWRCB), California Energy Commission (CEC), Department of 

Public Health (DPH), California Public Utilities Commission (CPUC), Air Resources Board 

(ARB), California Bay-Delta Authority (CBDA), and the US Bureau of Reclamation (USBR), 

with the contribution of the California Urban Water Conservation Council and water 

suppliers/purveyors and organizations through public workshop and meetings. 

Several important facts of the scope of the 20x2020 Plan are summarized below: 

1. The Plan addresses only urban water use and conservation, not agricultural water use; 

2. The Plan addresses only potable water use. Urban potable water use includes all 

residential, commercial, institutional, and industrial users as well as non-revenue water. 

Non-potable recycled water was excluded while estimating baseline per capita urban water 

use to give credit to agencies that have promoted recycled water in the past. Additional use of 

recycled water will be a significant method by which regions can continue to offset baseline 

potable urban water demand to meet the 2020 goals; 

3. The plan does not address water supplied by customers for their own use. The plan 

focuses on potable water supplied in municipal distribution systems and does not include 

quantities of self-supplied water (groundwater or surface water) in per capita use 

calculations. 

4. The plan recommends actions that will reduce per capita use, not total urban use, by 20 

percent. Since the population is always increased, total urban water use will never go 

down, therefore the plan aims at improving water supply reliability and water use efficiency. 

5. This plan does not set targets for individual water suppliers. There are wide variations 

among water suppliers. This plan does not provide specific guidance to move from regional 

planning targets to supplier-specific targets. Water suppliers are to develop their own plan to 

meet the state goals. 

The 20x2020 plan is based on the 2005 baseline urban water use. As shown in Table 11-3, the 

total baseline for the South Coast region is 253 Gallons Per Capita Day, which approximately 

amounts to 6.37 million acre-feet per year using the projected 2020 population of 22.5 million in 

the South Coast Hydrologic Region. As shown in Table 11-3, the average water use for the 

industrial sector is approximately 8% of the total water use in the South Coast region. 
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Proposed Amended Regulation XX Part I - 109 November 2, 2010 

TABLE 11-3 

Urban Water Use Pattern in 2005 for South Coast Hydrologic Region 

Water Use 

Residential (Single-and Multi-Family) 174 GPCD 

Commercial and Institutional 25 GPCD 

Industrial 21 GPCD 

Un-Reported Water 33 GPCD 

Total Baseline 253 GPCD (6.37 MAF per year) 

Reference: Table 3 of the 20x2020 Water Conservation Plan, February 2010. Total projected 2020 population = 

22.5 million. Therefore, 253 GPCD = (253 gallons per capita per day)(22.5 million)(365 days/year)(1 acreft/326,000 gals = 6.37 million acre-feet/year = 6.37 MAF/year) 

TABLE 11-1 

Urban Water Use in South Coast Hydrologic Region 

After establishing the 2005 baseline, the Agency Team held numerous public 

meetings/workshops to establish the conservation targets and develop recommendations for 

future actions to achieve the targets. 

Many urban water suppliers currently implement and enforce the 14 Best Management Practices. 

The Agency Team studied the results of the current actions and estimated future savings based 

on implementing current BMPs listed in Table 11-4. The Agency Team also evaluated new 

measures. Estimated savings for current and new measures are listed in Table 11-5. 

The nine (9) Agency Team’s recommended actions to achieve the Governor’s statewide strategic 

goal of 20x2020 are listed below: 

1. Establish a statewide conservation strategy 

2. Reduce landscape irrigation demand 

⎯ Require water-efficient landscapes at state-owned properties 

⎯ Support the implementation and enforcement of landscape design and irrigation 

programs and the development of new landscape programs 

⎯ Mandate the landscape irrigation Best Management Practices (BMP) 
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Proposed Amended Regulation XX Part I - 110 November 2, 2010 

TABLE 11-4 

 List of Best Management Practices (BMPs) 

TABLE 11-5 

Summary of 2020 Savings from All Evaluated Measures for South Coast Region 

Water Saving (GPCD) 

Efficiency Code Water Savings 

Residential – Indoor 4 

Residential – Outdoor 0 

Commercial, Institutional, Industrial (CII) 1 

2020 Water Savings from Cost Effective Measures 

Residential – Indoor 2 

Large Landscape 4 

Commercial, Institutional, Industrial (CII), 7 

Non-Revenue Water 4 

Grant funded 1 

Efficient Clothes Washers 2 

Residential Flow Controllers 3 

Total for Basic Measures 24 

Accelerated coverage goals 7 

Recycling 4 

Water loss controls 4 

Irrigation restrictions (2 days/week) 13 

Miscellaneous measures 2 

Total Additional Measures 29 

Total Savings 53

Reference: Table 7 of the 20x2020 Water Conservation Plan, February 2010 

BMP1 Water survey programs for residential customers 

BMP2 Residential plumbing retrofit 

BMP3 System water audits, leak detection and repair 

BMP4 Metering with commodity rates for all new connections and retrofit of existing 

unmetered connections 

BMP5 Large landscape conservation programs and incentives 

BMP6 High efficiency clothes-washing machine financial incentive program 

BMP7 Public information programs 

BMP8 School education programs 

BMP9 Conservation programs for commercial, industrial, institutional (CII) 

BMP10 Wholesale agency assistance programs 

BMP11 Retail conservation pricing 

BMP12 Conservation coordinator 

BMP13 Water waste prohibition 

BMP14 Residential ultra-low-flush toilet (ULFT) replacement programs 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

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Proposed Amended Regulation XX Part I - 111 November 2, 2010 

3. Reduce water waste 

⎯ Accelerate installation of water meters 

⎯ Establish a state standard for water meter accuracy 

⎯ Revise the water loss BMP to incorporate improved methodologies and accelerate 

coverage goals 

4. Reinforce efficiency codes and related BMPs 

⎯ Obtain authorization for state standards for high efficiency clothes washers 

⎯ Support landscape irrigation equipment standards 

⎯ Accelerate replacement of inefficient showerheads, toilets and urinals 

⎯ Accelerate adoption of proven water saving technologies in new businesses 

5. Provide financial incentives 

⎯ Encourage or mandate conservation water pricing 

⎯ Provide grants, loans, and rebates to wholesale and retail water suppliers and 

customers 

⎯ Establish a public goods charge for water 

⎯ Fund the installation of water meters 

6. Implement statewide conservation public information and outreach campaign 

7. Provide new or exercise existing enforcement mechanisms to facilitate water 

conservation 

⎯ Require implementation of water conservation as a condition to receive state financial 

assistance 

⎯ Take enforcement actions to prevent waste and unreasonable use of water 

⎯ Provide additional enforcement tools for water suppliers 

8. Investigate potential flexible implementation measures 

⎯ Investigate requiring conservation offsets for water demand generated by new 

development 

⎯ Investigate establishment of a cap-and-trade regime 

9. Increase the use of recycled water and non-traditional sources of water 

For comparison, the water savings from Table 11-5 are converted to million gallons of water 

savings per year and graphically shown in Figure 11-2. It should be noted that from Table 11-5, 

reducing water in irrigation to 2 days/week is the measure that would generate the most water 

savings. The two most important conservation measures which generate more than 50% of the 

conservation amount are conservation in irrigation and residential sector. The residential sector 

is expected to conserve more than the commercial, institutional, and industrial sector. 

Interestingly though is that the conservation from water loss controls is as significant as the 

conservation estimated for additional water recycling. 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

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Proposed Amended Regulation XX Part I - 112 November 2, 2010 

FIGURE 11-2 

Comparison between Measures in the 20x2020 Plan 

Table 11-7 shows a comparison of SOx RECLAIM total water and potable water demand to the 

water demand and savings of the statewide strategic plan of the South Coast Hydrologic Region. 

The total water demand for the proposed SOx RECLAIM project is about 0.02% of the total 

water usage in the South Coast Hydrologic Region. The increase in potable water demand of the 

proposed SOx RECLAIM project (for scenario that used wet gas scrubbers if future supplies of 

recycled water are available) is about 0.05% of the potable water savings estimated for the CII 

sector of the South Coast Hydrologic Region in 2020. Staff believes that the impacts on water 

demand and potable water demand is negligible based on the information in the 20x2020 Plan. 

TABLE 11-7 

Comparison of water demand for SOx RECLAIM Project 

to the Statewide Strategic Plan of the South Coast Hydrologic Region 

Total Water Usage 

⎯ Baseline for South Coast region = 253 GPCD = 6.37 million acre-ft per year (MAF) 

⎯ Future water demand for SOx RECLAIM = 1,000 acre-ft per year total water 

⎯ Percentage = 1,000 / 6.37 million = 0.02 %

Potable Water Savings 

⎯ Savings estimated for Commercial, Institutional and Industrial sector for the South Coast 

region= 8 GPDC = 201,423 acre-ft per year 

⎯ Potable water demand for scenario where wet gas scrubbers (or SOx reducing catalysts) are used 

if future supplies of recycled water are available = 99,360 gals/day = 111 acre-ft per year. 

Percentage = 111 / 201,423 = 0.05%

⎯ Potable water demand for scenario where wet gas scrubbers are used if future supplies of 

recycled water are not available = 201,587 gals/day = 226 acre-ft per year. Percentage = 226 / 

201,423 = 0.11%

⎯Potable water demand for scenario where DeSOx reducing catalysts are used in FCCUs if future 

supplies of recycled water are not available = 108,436 gals/day = 121 acre-ft per year. 

Percentage = 121 / 201,423 = 0.06%
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 113 November 2, 2010 

11.4 Urban Water Management Plans 

The Urban Water Management Planning Act (Act) became effective on January 1, 1984, and 

requires that every urban water supplier that provides municipal and industrial water to more 

than 3,000 customers, or supplies more than 3,000 acre-feet per year (AFY) prepare and adopt an 

urban water management plan in accordance with prescribed requirements. The Act requires the 

water purveyors to provide information on water supply and demand in their service area, focus 

primarily on water supply reliability and water use efficiency measures and put strong emphasis 

on drought contingency planning and recycled water. With the passage of Senate Bills 610 and 

221 in 2001, the Urban Water Management Plan (UWMP) becomes more important. With SB 

610 and 221, the UWMP becomes a written verification and indication to whether or not the 

urban water suppliers can provide water to the people living in the area. The UWMP serves as 

the master plan for water supply and resources management, a guidance document for policy 

makers to secure a sustainable water supply, as well as an ultimate source of information to the 

citizens in the basin. Because of this magnitude of its importance, staff conducted a research on 

the UWMPs of the major suppliers in the basin to understand a big picture of the water supply 

and demand in the basin and to consciously and intelligently answer the following questions 

related to the SOx RECLIAM project: 

• What is the current and future water supply and demand in the basin? What is the distribution 

of water use in the basin? 

• What are the Best Management Practices (BMPs) recommended by the water experts to 

conserve water and secure water resources in California? What are their effectiveness and 

how much water that they can help to conserve? To what extend doesis recycled water used

in the basin? 

• How does the water demand increase for this SOx RECLAIM project measure up to the 

overall water use in the basin? Can the urban water suppliers supply this amount of 

increase? Can this amount of increase be mitigated? 

The information on the water supply/demand and water reliability analysis in the UWMPs of the 

three major water suppliers in the basin, Los Angeles Department of Water & Power (LADWP), 

West Basin Municipal Water District (WBMWD), and Metropolitan Water District of Southern 

California (MWD) are presented below. 

West Basin Municipal Water District (WBMWD) 

The WBMWD is the sixth largest water district in the state of California, serving a population of 

about 915,000 in 17 cities. The WBMWD currently supplies an average of 220,000 acre-feet of 

water annually combined of groundwater, imported water and recycled water. WBMWD is 

currently the wholesale supplier of recycled water for three refineries in the SCAQMD – 

Refinery 2, 3, and 6, and will expand its service to deliver recycled water to the sulfuric acid 

plant in 2013. 

The WBMWD actively produces and provides recycled water, supports a desalination project, 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

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Proposed Amended Regulation XX Part I - 114 November 2, 2010 

and conducts numerous programs to promote water conservation. Some of its accomplishments 

are highlighted below: 

⎯ In 1992-1993, the WBMWD received state and federal funding to construct a world-class 

state of the art water treatment/recycling facility in the City of El Segundo named Edward C. 

Little Water Recycling Facility. The WBMWD is in the process of expanding the capacity 

of its facility to double the amount of recycled water produced in 2013. To promote the use 

of recycled water, the WBMWD advances funds for retrofit expenses which can be 

reimbursed through the water bills. The onsite plumbing retrofit costs are amortized over a 

10 years period at WBMWD’s cost of funds. Repayment can be made using the differential 

between potable and recycled water rates so that customers never pay more than potable rate. 

Once the loan is repaid, the rate reverts back to the current recycled rate 

⎯ The WBMWD incorporates all 14 Best Management Practices (BMPs) recommended by the 

California Urban Water Conservation Council (CUWCC) such as distributing water-saving 

showerheads and toilets, smart controllers, and conducting water recycling and water 

education workshops to increase public awareness about water conservation and help to 

increase water reliability within the region. As an example, providing $50 rebates for 

customers to replace/install Ultra-Low-Flush Toilet (ULFT) has saved from 44 acre-ft (1,544 

toilets) to 123 acre-ft per year (4,234 toilets) in 5 years from 2000-2004. In addition, with 

the demand on the water supply continuing to increase, the WBMWD proactively pursues a 

demonstration-scale ocean-water desalination facility to explore the feasibility of large-scale 

ocean-water desalination for future supply. 

The WBWMD is in the process of developing its 2010 Urban Water Management Plan (UWMP) 

which is due to the Department of Water Resources in 2011. As shown in its 2005 UWMP, the 

WBWMD is able to supply reliable water to meet the demands projected for 25 years from 2005 

to 2030 in both single dry-year scenarios or multiple dry-year scenarios. The projected water 

demands, supplies, and surplus from the 2005 UWMP are presented in Table 11-8 for multiple 

dry-water years. The projected multiple dry-year scenarios were based on the low rainfall years 

in FY 2001-02, 2002-03, and 2003-04. The WBMWD estimates that they will supply 

reliable water with a surplus varying from 7,800 acre-feet per year to 33,236 acre-feet per 

year for the next 30 years. 

TABLE 11-8 

Projected Water Demands and Supplies for Multiple Dry-Year Reliability 1, 2

Note: 1) WBMWD 2005 Urban Water Management Plan, Chapter 4. 2) Supply reliability covers only water demand in 

municipal/industrial sectors and does not include replenishment. 

Year 2010 

(Acre-Feet) 

Year 2014 

(Acre-Feet) 

Year 2015 

(Acre-Feet) 

Year 2020 

(Acre-Feet) 

Year 2030 

(Acre-Feet) 

Groundwater 56,797 56,797 56,797 56,797 56,797 

Imported Water 135,334 130,940 135,334 135,334 135,334 

Recycled Water 21,848 31,000 32,500 36,250 43,750 

Ocean Desalination 0 20,000 20,000 20,000 20,000 

Total Supply 213,979 238,737 244,631 248,381 255,881 

Total Demand 206,188 205,855 211,395 216,733 227,816 

Surplus 7,791 32,882 33,236 31,648 28,065 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

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Proposed Amended Regulation XX Part I - 115 November 2, 2010 

FIGURE 11-1 

Projected Water Supplies for WBWMD Area (Year 2030) 

Regarding recycled water, the WBWMD produces five different types of water quality from 

irrigation water (tertiary treated meeting California Title 22 regulation) to ultra pure Reverse 

Osmosis water for groundwater injection and industrial boiler feed as shown in Table 11-9. 

The recycled water from WBMWD is used in various commercial, institutional and industrial 

operations, but mostly by refineries, with the distribution shown in Figure 11-2. 

FIGURE 11-2 

Distribution of Recycled Water Use for WBWMD Area 

Refineries

72%

Groundwater

Barriers

16%

Parks

3%

Schools

1%

Others

8%

Regarding the WBMWD’s water rates, the irrigation water is typically sold at a cost of $73 per 

acre-foot whereas ultra pure Reverse Osmosis Water is sold at a cost of $750 per acre-foot as 

shown in Table 11-1-B. Refinery A, B and D purchase a combination of nitrified water, one 

single pass pure RO water, and ultra pure RO water. The consultants (ETS/AEC) have 

conservatively used a rate varying from $800 per acre-ft - $1,350 per acre-ft to estimate the 

annual water costs for SOx RECLAIM project accordingly to the information given to 

them by the refineries. 

The recycled water consumption by the three refineries located in the WBMWD’s service areas 

is summarized in Table 11-10, side-by-side with the amount of recycled water that the refineries 

reported to staff, and the potential increase demand for this SOx RECLAIM project. The total 
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Proposed Amended Regulation XX Part I - 116 November 2, 2010 

recycled water purchased by the three refineries from WBMWD is about 18,945 acre-ft in 2008-

09. The total recycled water usage reported to the District is about 21,785 acre-ft. The total 

increase due to SOx RECLAIM is about 678 acre-ft per year, approximately 3% increase over 

the baseline of 21,785 acre-ft. 

As shown in its 2005 UWMP and the 2008-2009 Annual Report, the WBWMD has a potential to 

increase its supply of recycled water to 70,000 - 100,000 acre-feet, and will reach 31,000 acre-ft 

by 2014, 32,500 acre-ft by 2015, and 36,250 acre-ft by 2020. Using the current distribution of 

72% for refineries, staff projects approximately 22,320 acre-ft will be available to the three 

refineries in 2014, 23,400 acre-ft by 2015, and 26,100 acre-ft by 2020. The projected supply 

of recycled water is sufficient to cover the current demand of 21,785 acre-ft and the 

potential increase of 678 acre-ft for SOx RECLAIM project at these three refineries. It is 

anticipated that the refineries will not implement all of the SOx RECLAIM measures at the same 

time in 2014, and they have extra underground pumping capacity available to balance the 

demand when in need. 

TABLE 11-9 

Type of Recycled Water & Rates 1 

Disinfected Tertiary 

Water 

Treated secondary water from Hyperion that undergoes 

coagulation, flocculation, filtration and disinfection to meet the 

Title 22 standards. Tertiary water can be used for a wide variety 

of industrial and irrigation purposes where high-quality, nonpotable water is needed. 

$73 -$169 

per acre-ft 

Nitrified Water Nitrified water is tertiary water that has been nitrified to remove 

ammonia, which can be corrosive to pipe material. This water is 

used in cooling towers. 

$292 

per acre-ft 

Softened RO Water Secondary treated water from Hyperion that has been treated 

with microfiltration, lime softeners and reverse osmosis. This 

water is used to replenish groundwater supplies. This water is 

superior to State and Federal drinking water standards. 

$430 per 

acre-ft 

Pure RO Water Secondary treated water from Hyperion that has been treated 

with microfiltration and reverse osmosis. This water is used for 

low pressure boiler feed water for large scale industrial sites 

such as refineries. 

$568 

per acre-ft 

Ultra Pure RO Water Secondary treated water from Hyperion that has been treated 

with microfiltration and treated twice with reverse osmosis. 

This water is used for high pressure boiler feed water for large 

scale industrial sites such as refineries. This water is so pure 

that there is no mineral buildup and it can be used multiple times 

as boiler feed water before being discharged. 

$750 

per acre-ft 

Note: 1) WBMWD 2005 Urban Water Management Plan, Chapter 8 – Water Recycling. 2) Rates from Chapter 7 of the 

WBMWD 2005 UWMP. 3) ETS/AEC has used a water rate of $2,794 per million gallons (or $910 per acre-ft, 20% higher than 

WBMWD’s rate for the ultra pure RO water) in the cost analysis for SOx RECLAIM. 

TABLE 11-10 
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Proposed Amended Regulation XX Part I - 117 November 2, 2010 

Water Use and Potential Increase (Acre-Ft) 

WBWMD’s 

2008-09 Water Use 

Report 1, 2, 3

Refinery’s Data 

Reported to 

SCAQMD 4

Potential 

Increase 5

Refinery 3 8,587 8,650 169 

Refinery 6 4,759 6,853 254 

Refinery 2 5,599 6,282 255 

Recycled Water Use by Refineries 18,945 21,785 678 

Recycled Water Use by All Customers 23,588 

Capability of WBMWD Projected: 31,000 by 2014; 32,500 by 2015; 36,250 by 

2020; and 43,750 by 2030. Capability: 70,000 - 100,000 

Note: 1) Refineries purchase a combination of nitrification, pure single pass RO, and ultra pure double pass RO. 2) Refinery’s

recycled water use is about 90% - 95% of the total recycled water use by the city. 3) Refineries purchase 75% - 80% recycled 

water produced by WBWMD. The variation for past 10 years is shown. 4) SCAQMD’s Survey. 5) Potential increase in water 

use by addition of wet gas scrubbers for FCCUs and SRUs, and by modification/addition of fuel gas treatment. 

Los Angeles Department of Water & Power (LADWP) 

On average, LADWP supplies 621,765 acre-feet of water per year (5-year average of supply 

from 1980-2009). The water distribution in the LADWP service area is shown in Figure 11-3. It 

should be noted that LADWP actively implements all 14 BMPs recommended by the California 

Urban Water Conservation Council (CUWCC) 63 and the DWR described in the 2009 California 

Water Plan. LADWP also implements many water conservation efforts (e.g. ultra-low-flush 

toilet retrofit program, indoor and outdoor conservation), public outreach, and school education 

program. As a result, the water usage in the city is the same as it was 20 years ago despite an 

increase in population of about 750,000 people. 64

LADWP has a water shortage contingency plan with actions that can be undertaken in response 

to water supply shortages, including up to 50% reduction in water supply. Some of the actions 

identified in the water shortage contingency plan and currently implemented are: restricting 

landscape irrigation to two times a week, developing a large industrial customer incentive 

program that provides a monetary credit for all water conservation, irrigating public parks only 

with recycled water, requiring recycled water to be used at commercial car washes and 

construction projects, and enforcing a tired billing structures to promote water use efficiently.65

 

63 The California Urban Water Conservation Council (CUWCC) is an organization formed in 1991 comprised of 

water suppliers and governmental agencies with a mission to promote water conservation in California. The 

CUWCC was instrumental in developing the “Memorandum of Understanding Regarding Urban Water 

Conservation in California (MOU) signed by numerous local water suppliers in California. The MOU identifies 

fourteen “Best Management Practices (BMPs) listed in Table 11-4 of this Staff Report, commits water suppliers to 

develop comprehensive conservation programs to implement the 14 BMPs, and establishes the CUWCC to monitor 

the implementation of the BMPs and to maintain and update the list of BMPs. 

64 City of Los Angeles Department of Water and Power, 2005 Urban Water Management Plan. 

65 To promote the use of water efficiently, LADWP restructured its water rates to a two-tier structure in 1993 with a 

lower first tier rate for water used within a specified allotment, and a higher second tier rate for every billing unit 

that exceeds the first tier allotment. The water rates are also higher during shortage periods. For example, the Tier 1 

rate for commercial and industrial customers is $1.21 per hundred cubic feet, and Tier 2 rate is $3.70 per hundred 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 118 November 2, 2010 

The projected water demand/supply for the LADWP is presented in Figure 11-4 and Table 11-11 

for the next 30 years. The projected water supply from municipal & industrial recycled water is 

only about 4% of the portfolio. It is interesting to note that LADWP expected to purchase more 

than 60% of its water from the Metropolitan Water District in 2030. LADWP projected that 

they will have reliable water supply for the next 30 years for the area that they serve. 

FIGURE 11-3 

Water Distribution in the LADWP Service Area 

FIGURE 11-4 

Water Supply in the LADWP Service Area (Year 2030) 

 

cubic feet during 10% shortage period. The Tier 1 rate remains at $1.21 for 15%, 20% and 25% shortage periods 

but Tier 2 rate increases to $4.44, $5.18 and $6.05 per hundred cubic feet in these shortage periods, respectively. 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 119 November 2, 2010 

TABLE 11-11 

LADWP Projected Water Demands and Supplies for Multiple Dry-Year Reliability 1, 2

Note: 1) LADWP 2005 Urban Water Management Plan, Chapter 6. 2) Project with existing water conservation program. 

Metropolitan Water District of Southern California (MWD) 

The MWD is a public agency formed in the late 1920's. Its function is to manage the supply of 

water in Southern California. Its first function was building the Colorado River Aqueduct to 

convey water from the Colorado River in the early 1940s. In 1960, to meet increasing water 

demands, MWD contracted water supplies from the State Water Project (SWP) via the California 

Aqueduct, which is owned and operated by the DWR. The MWD currently receives imported 

water from two main sources: the Colorado River and the SWP. The MWD’s service area 

covers a portion of Los Angeles, Orange, Riverside, San Bernardino, San Diego and Ventura 

counties. The MWD is a wholesaler and has no retail customers. The MWD distributes treated 

and untreated water directly to its 26 member agencies including 14 cities, 11 municipal water 

districts, and one county water authority (San Diego). 

On daily average, the MWD delivers 6,023 AF. The record annual sales are 2.5 MAF in 1900. 

The projected sales for the next couple years for the commercial, institutional, industrial retail 

sector are estimated to be 1 MAF as shown in Table 11-12. Water is supplied at a unit price of 

$701 per acre-foot for treated water and $484 per acre-foot for untreated water. A balance of 

water supply and demand in Table 11-13 shows that MWD can provide reliable water under 

multiple dry year hydrologies. In addition, MWD has identified buffer supplies, including 

additional State Water Projects groundwater storage and transfer that could serve as a supply 

when additional water is needed.66

 

66 The 2005 Regional Urban Water Management Plan – Metropolitan Water District of Southern California. 

November 2005. Metropolitan Water District website www.mwdh2o.com.

Year 2010 

(Acre-Feet) 

Year 2015 

(Acre-Feet) 

Year 2020 

(Acre-Feet) 

Year 2030 

(Acre-Feet) 

Existing Supplies 

Los Angeles Aqueduct 120,000 120,300 120,300 120,300 

Groundwater 95,000 95,000 95,000 95,000 

Municipal & Industrial Recycled Water 1,950 1,950 1,950 1,950 

Subtotal 217,250 217,250 217,250 217,250 

Planned Supplies 

Municipal & Industrial Recycled Water 10,000 18,000 20,000 29,000 

Seawater Desalination 0 13,500 13,500 13,500 

Water Transfer 40,000 40,000 40,000 40,000 

Subtotal 50,000 71,500 73,500 82,500 

MWD Water Purchases 449,750 450,250 475,250 513,250 

Total Supply 717,000 739,000 766,000 813,000 

Total Demand 717,000 739,000 766,000 813,000 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 120 November 2, 2010 

Just like the LADWP, the MWD has its water shortage contingency plan that outlines the 

necessary actions to be taken during water supply shortages including up to 50% reduction in its 

water supplies. The MWD also has a water surplus and drought management plan that outlines 

various resources to minimize the possibility of severe shortages by integrating the management 

of surplus and shortage into one plan. Through effective management, the MWD indicated in 

its 2005 UWMP that it expected to be 100 percent reliable (with surplus supply) in meeting 

all demands in its service area. 

TABLE 11-12 

MWD Projected Water Demands in Commercial. Industrial, Institutional Retail Sector 

Reference: Table A.1-10 of MWD’s Urban Water Management Plan 2005. 

TABLE 11-13 

MWD Projected Water Demands and Supplies for Multiple Dry-Year Reliability

Reference: Table II-8 Multiple Dry Year Supply Capability and Projected Demands, The Regional Urban Water Management Plan of 

Metropolitan Water District of Southern California, November 2005. 

Year 2010 (AcreFeet) Year 2020 

(Acre-Feet) 

Year 2030 (AcreFeet) 

Los Angesles 507,500 519,500 521,200 

Orange 179,200 185,900 189,900 

Riverside 64,400 78,500 93,000 

San Bernardino 44,300 51,700 59,100 

San Diego 167,200 171,400 174,500 

Ventura 37,800 42,100 46,300 

Total 1,000,400 1,049,100 1,084,000 

Year 2010 

(Acre-Feet) 

Year 2015 

(Acre-Feet) 

Year 2020 

(Acre-Feet) 

Year 2030 

(Acre-Feet) 

Existing Supplies 

In-Basin Storage 514,000 518,000 502,000 470,000 

California Aqueduct 912,000 912,000 912,000 912,000 

Colorado River Aqueduct 722,000 699,000 699,000 699,000 

Supplies Under Development 

In Basin Storage 78,000 103,000 103,000 103,000 

California Aqueduct 330,000 215,000 299,000 299,000 

Colorado River Aqueduct 95,000 460,000 400,000 400,000 

Transfer to Other Agencies 0 (35,000) (35,000) (35,000) 

Metropolitan Supply Capability 2,651,000 2,872,000 2,880,000 2,848,000 

Firm Demands on Metropolitan 2,392,000 2,302,000 2,309,000 2,585,000 

Potential Reserve and Replenishment Supplies 259,000 502,000 473,000 155,000 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 121 November 2, 2010 

11.5 Conclusion 

In summary, the information and analysis above shows the following: 

• The water demand increase due to this SOx RECLAIM project (consisting of 

installing/operating eleven wet gas scrubbers and two dry gas scrubbers at eleven major 

facilities to reduce 6.2 tons per day of SOx) is negligible at 1,000 acre-feet per year 

compared to the water use of 6.37 million acre-feet per year for the South Coast Hydrologic 

region. It represents 0.02% increase over the current water usage baseline. 

• The potable water demands of this SOx RECLAIM project are approximately from 1211 

acre-ft per year to 226 acre-ft per year which represent about 0.065% - 0.11% of the potable 

water savings of 200 thousand acre-feet per year estimated for the South Coast Hydrologic 

region. 

• Table 11-4 provides a comparison of the water demand for SOx RECLAIM project with the 

water use/demand in California, South Coast Hydrologic region and other local water 

suppliers. The purpose of Table 11-14 is to put the water demand of SOx RECLAIM project 

into the perspective of others. 

TABLE 11-14

Comparison of Water Supplies and Demands

Water Use 

(Acre-Feet Per Year)

California (Year 2005 Urban Use) 7,900,000 

South Coast Hydrologic Region (Year 2005 Urban Use) 6,370,000 

MWD’s contract with DWR (State Water Project) 1,910,000 

MWD’s entitlement from Colorado River through DWR 1,200,000 

MWD’s projected supplies (Year 2030) 2,848,000 

MWD’s projected supplies for commercial, industrial, 

institutional sector (Year 2030) 

1,084,000 

Groundwater production in MWD’s service area 1,600,000 

LADWP – All sectors 621,765 

LADWP – Industrial sector 23,384 

Recycled water supplied by MWD 355,000 

Projected total water supplied by West Basin (Year 2030) 255,881 

Projected recycled water supplied by West Basin (Year 2030) 43,750 

Baseline for 11 Major SOx RECLAIM Facilities 57,798 

Project Increase for SOx RECLAIM 1,000 

• The water suppliers can reliably supply water, including recycled water, for the next 30 years 

and meet the nominal increase in water demand from this project based on the predicted 

water supply/demand shown in the 2005 UWMPs. 
Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 122 November 2, 2010 

• The average water use in industrial sector is only about 8% for the South Coast Hydrologic 

Region, 4% for the LADWP service area, and 25% for the MWD. The Best Management 

Practices for conserving water focus in the areas that can significantly reduce water such as 

irrigation and residential sector. The Agency Team of the 20x2020 Plan estimated that water 

savings from the Commercial, Institutional, Industrial sector only contributes approximately 

15% to the overall water savings required to meet the 20% reduction by 2020 asked for the 

Governor. Increased use of recycled water, if available, is a BMP that can be used to 

mitigate increase in water demand from this project. 

• The consultants have appropriately used a rate varying from $800 per acre-ft to $1,350 per 

acre-ft to estimate the annual water costs for SOx RECLAIM project accordingly to the 

information provided to them by the refineries. 

While this project would result in water demand that can be viewed as meaningful, the proposal 

can be met by current and future portable and recycled water suppliers. The substantial air 

quality and health benefits of the project far outweigh the potential water impacts. However, in 

the spirit of carrying out abundance of caution in response to the drought affecting California, 

CEQA staff made the determination that the SOx RECLAIM project would be considered 

significant if recycled water is not available. Please refer to the August 18, 2010 Draft Program 

Environmental Assessment document for further information. 
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 123 November 2, 2010 

Chapter 12 – Costs & Cost Effectiveness Analysis 

12.1 Scenario Analysis 

Staff conducted the following four scenario analysis to estimate overall emission reductions for 

the project, costs, cost effectiveness, control factors, and RTC reductions. 

Scenario 1 – Most Stringent 

1 ppmv for FCCUs (98% control), 

1 ppmv for SRU/TGTUs 

Tier I level for boilers/heaters (40 ppmv, or to appropriate sensible levels) 

5 ppmv for coke calciner 

5 ppmv for sulfuric acid 

1 - 2 ppmv (99% control) for glass furnace 

1 - 2 ppmv (99% control) for cement plant 

Scenario 2 – Consultants’ Recommendations 

5 ppmv for FCCUs, 

5 ppmv for SRU/TGTUs 

Tier I level for boilers/heaters (40 ppmv, or to appropriate sensible levels) 

10 ppmv for coke calciner 

10 ppmv for sulfuric acid 

1 – 2 ppmv (99% control) for glass furnace 

1 - 2 ppmv (99% control) for cement plant 

Scenario 3A – Staff’s Recommendations on January 8, 2010 

The controls with cost effectiveness less than $50K per ton at the following proposed BARCT 

levels: 

5 ppmv for FCCUs 

5 ppmv for SRU/TGTUs 

Tier I level for boilers/heaters (40 ppmv) 

10 ppmv for coke calciner 

10 ppmv for sulfuric acid 

5 ppmv for glass furnace 

5 ppmv for cement plant 

Scenario 3B – Alternative to Staff’s Recommendation in Scenario 3A. 

The controls with cost effectiveness less than $50K per ton at the following proposed BARCT 

levels: 

7 ppmv for FCCUs 

10 ppmv for SRU/TGTUs, coke calciner, glass, cement 

Tier I level for boilers/heaters (40 ppmv) 

The results were presented in Table 12-1 using the information provided by ETS/AEC and 

NEXIDEA. In addition, staff added two more scenarios in the analysis, Scenario 4 and 5. In 

Scenario 4, there would be no BARCT for SRU/TGs and Scenario 5 is to meet the minimum 

requirements in the 2007 AQMP. Please refer to Section 12.34 for further information. 
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 124 November 2, 2010 

After January 8, 2010 Governing Board meeting, staff received feedback from WSPA and the 

refineries, and as a result, Scenario 3A was modified to not include costs associated with the 

modifications for boilers/heaters to meet the existing Tier 1 BARCT at 40 ppmv. In addition, 

modification to the cost effectiveness was made to exclude any incurred costs and emission 

reductions from projects that have already been completed. The results in Table 12-1 for 

Scenario 3A are revised to: 

Scenario 3A – Staff’s Current Recommendation 

Present Worth Values = $745 million – $116 million (for boilers/heaters) = $630 million 

Emission reductions = 6.20 – 0.85 (for boilers/heaters) – 1.00 (reductions that already 

been achieved) = 4.36 tons per day 

Weighted average cost effectiveness = $15,845 per ton 
Final Staff Report – Part 1 Chapter 12 – Costs & 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 125 

TABLE 12-1 – Costs & Cost Effectiveness 

Facility Refinery 1 Refinery 2 Refinery 3 Refinery 4 Refinery 5 

Control Technology /Vendor

Present Worth Value ($ million) 76 133 95 78 75* 

Scenario 1 - most stringent

Performance Level 98% 98% 98% 98% 98% 

Emission Reductions (tpd) 0.60 0.30 0.35 0.24 0.94 

Cost Effectiveness ($/ton) 14,000 48,000 29,500 35,200 10,700 

BARCT

BARCT/Start EF

Scenario 2 - consultants

Performance Level 5 ppmv 5 ppmv 5 ppmv 5 ppmv 5 ppmv 

Emission Reductions (tpd) 0.58 0.19 0.28 0.20 0.87 

Cost Effectiveness ($/ton) 14,437 76,211 36,636 42,103 11,600 

BARCT 13.38 lbs/Mbarrels

BARCT/Start EF 0.26 (=2.29/52.06)

Scenario 3A - staff's

Performance Level 5 ppmv 5 ppmv 5 ppmv 5 ppmv 5 ppmv 

Emission Reductions (tpd) 0.58 0.28 0.20 0.87 

Cost Effectiveness ($/ton) 14,437 >50,000 36,636 42,103 9,398 

BARCT 3.25 lbs/Mbarrels

BARCT/Start EF 0.06 (=3.25/52.06)

Scenario 3B - Alternative

Performance Level 7 ppmv 7 ppmv 7 ppmv 7 ppmv 7 ppmv 

Emission Reductions (tpd) 0.57 0.14 0.25 0.19 0.83 

Cost Effectiveness ($/ton) 18,941 18,941 18,941 18,941 18,941 

BARCT 3.23 lbs/Mbarrels

BARCT/Start EF 0.06 (=3.23/52.06)

WGS - BELCO

98% for 6 refineries

0.36 lbs/Mbarrels

0.01 (=0.36/52.06)

5 ppmv for 6 ref - 5 new wet scrubbers and 1 existing wet scru

5 ppmv for 5 ref - 4 new wet scrubbers, 1 existing wet scrub

7 ppmv with DeSOx catalysts

*Refinery 5 revised its capital cost estimate from $70 million (Authority for Expenditures AFE) to $60 million in March 2010. Suthe cost effectiveness in Scenario 3A from $11,600 per ton to $9,398 per ton.
Final Staff Report – Part 1 Chapter 12 – Costs & 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 126 

TABLE 12-1 (Continue) 

Equipment 

Facility Refinery 1 Refinery 2 Refinery 3 Refinery 4 Refiner

Control Technology /Vendor Emerachem WGS-TriMer Emerachem for 2 

SRUs & Tri Mer

Emerachem WGS-Tri

Present Worth Value ($ million) 26 60 17 19 64 

Scenario 1 - most stringent

Performance Level

Emission Reductions (tpd) 0.13 0.20 0.15 0.04 0.07 

Cost Effectiveness ($/ton) 22,410 32,900 12,881 54,686 95,80

BARCT lbs/hr

BARCT/Start EF (=2.92/8.39)

Scenario 2 - consultants

Performance Level 5 ppmv 5 ppmv 5 ppmv 5 ppmv 5 ppm

Emission Reductions (tpd) 0.13 0.17 0.15 0.04 0.06 

Cost Effectiveness ($/ton) 22,409 39,000 12,880 54,705 123,16

BARCT lbs/hr

BARCT/Start EF 0.46 (=3.89/8.39)

Scenario 3A - staff's

Performance Level Already met 1WGS 5 ppmv Emera 5 ppmv 

Emission Reductions (tpd) 0.13 0.17 0.15 

Cost Effectiveness ($/ton) n/a 39,000 12,880 >50,000 >50,00

BARCT lbs/hr

BARCT/Start EF 0.63 (=5.28/8.39)

Scenario 3B - Alternative

Performance Level Already met 1WGS 10ppmv 1WGS 10 ppmv 

Emission Reductions (tpd) 0.13 0.13 0.11 

Cost Effectiveness ($/ton) n/a 48,606 34,695 >50,000 >50,00

BARCT lbs/hr

BARCT/Start EF 0.76 (=6.39/8.39)

10 ppmv for 3 refineries. 1 already met reduction. 0 Emerachem. 4 new 

6.395.283.89

5 ppmv for 4 refineries. 1 already met reduction. 1 with Emerachem. 3 ne

0.35

5 ppmv for 6 refineries. 3 with Emerachem. 5 new wet scrub

98% for 6 refineries

2.92

Sulfur Recovery Units/Tail Gas
Final Staff Report – Part 1 Chapter 12 – Costs & 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 127 

TABLE 121-1 (Continue) 

Equipment 

Facility Refinery 1 Refinery 2 Refinery 3 Refinery 4 Refinery 

Control Technology /Vendor FGT FGT FGT FGT FGT 

Present Worth Value ($ million) 1.4 20 15 16 64 

Scenario 1 - most stringent

Performance Level

Emission Reductions (tpd) 0.06 0.07 0.04 0.35 0.33 

Cost Effectiveness ($/ton) 2,395 30,948 46,906 4,903 21,071 

BARCT

BARCT/Start EF 0.2 (=6.76/33)

Scenario 2 - consultants

Performance Level

Emission Reductions (tpd) 0.06 0.07 0.04 0.35 0.33 

Cost Effectiveness ($/ton) 2,395 30,948 46,906 4,903 21,071 

BARCT

BARCT/Start EF 0.2 (=6.76/33)

Scenario 3A - staff's

Performance Level

Emission Reductions (tpd) 0.06 0.07 0.04 0.35 0.33

Cost Effectiveness ($/ton) 2,395 30,948 46,906 4,903 21,071 

BARCT

BARCT/Start EF 0.2 (=6.76/33)

Scenario 3B - Alternative

Performance Level

Emission Reductions (tpd) 0.06 0.07 0.04 0.35 0.33

Cost Effectiveness ($/ton) 2,395 30,948 46,906 4,903 21,071 

BARCT

BARCT/Start EF 0.2 (=6.76/33)

To Tier I level

40 ppmv = 6.76 lbs/mmscft40 ppmv = 6.76 lbs/mmscft40 ppmv = 6.76 lbs/mmscft

To Tier I levelTo Tier I levelTo Tier I level

40 ppmv = 6.76 lbs/mmscft

Refinery Boilers/Heaters
Final Staff Report – Part 1 Chapter 12 – Costs & 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 128 

TABLE 12-1 (Continue) 

Equipment Coke Calciner

Facility Fac C Fac A Fac A 

Control Technology /Vendor WGS-BELCO Equip Mod-Cansolv WGS-BELCO 

Present Worth Value ($ million) 25.3 1.7 8.0 

Scenario 1 - most stringent 5 ppmv-1 wet scrubber

Performance Level 5 ppmv (90%) 5 ppmv (>95%) 

Emission Reductions (tpd) 0.32 0.04 

Cost Effectiveness ($/ton) 8,642 17,596 

BARCT 0.03 lbs/ton coke

BARCT/Start EF 0.01 (=0.03/2.47)

Scenario 2 - consultants 10 ppmv-1 wet scrubber

Performance Level 10 ppmv 10 ppmv 

Emission Reductions (tpd) 0.28 0.033 

Cost Effectiveness ($/ton) 9,902 5,556 

BARCT 0.11 lbs/ton coke 0.14 lbs/ton acid 

BARCT/Start EF 0.05 (=0.11/2.47) 0.04 (=0.14/3.93) 

Scenario 3A - staff's 10 ppmv-1 wet scrubber

Performance Level 10 ppmv modification to 10 ppmv 

Emission Reductions (tpd) 0.28 0.033 

Cost Effectiveness ($/ton) 9,902 5,556 

BARCT 0.11 lbs/ton coke 0.14 lbs/ton acid 

BARCT/Start EF 0.05 (=0.11/2.47) 0.04 (=0.14/3.93) 

Scenario 3B - Alternative 10 ppmv-1 wet scrubber

Performance Level 10 ppmv (80%) modification to 10 ppmv 

Emission Reductions (tpd) 0.28 0.033 

Cost Effectiveness ($/ton) 9,902 5,556 

BARCT 0.11 lbs/ton coke 0.14 lbs/ton acid 

BARCT/Start EF 0.05 (=0.11/2.47) 0.04 (=0.14/3.93) 

10 ppmv

not applicablenot applicablenot applicable

10ppmv - 1 WGS, 1 modifica

0.02 (=0.

10 ppmv

5 ppmv

not applicable

0.07 lbs/t

Sulfuric Acid Plant
Final Staff Report – Part 1 Chapter 12 – Costs & 

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 129 

TABLE 12-1 (Continue) 

Equipment 

Facility Kilns Coal Fired Boiler

Control Technology /Vendor WGS-TriMer Limestone Absorber-BoldEco DGS or Limestone Abs - BoldEco

Present Worth Value ($ million) 8.8 43.7 12.6 

Scenario 1 - most stringent 1 ppmv 1 ppmv 5ppmv

Performance Level 99% 95% (1-2 ppmv) 95% (5 ppmv) 

Emission Reductions (tpd) 0.19 0.25 0.36 

Cost Effectiveness ($/ton) 4,988 18,893 3,818 

BARCT 0.0058 lbs/ton glass 0.03 lbs/ton clinker 95%

BARCT/Start EF 0.002 (=0.0058/2.51) 0.6 (=0.03/0.05) 0.05 (=1-0.95)

Scenario 2 - consultants 1 ppmv 1 ppmv

Performance Level 99% 95% (1-2 ppmv) 

Emission Reductions (tpd) 0.194 0.25 

Cost Effectiveness ($/ton) 4,988 18,893 

BARCT 0.0058 lbs/ton glass 0.03 lbs/ton clinker

BARCT/Start EF 0.002 (=0.0058/2.51) 0.6 (=0.03/0.05)

Scenario 3A - staff's 5 pppmv - 2 WGS 5 ppmv - 2 DGS 

Performance Level 2WGS 95% (5 ppmv) 2DGS 93% (5ppmv) 

Emission Reductions (tpd) 0.186 0.248 

Cost Effectiveness ($/ton) 5,198 19,300 

BARCT 0.03 lbs/ton glass 0.04 lbs/ton clinker

BARCT/Start EF 0.01 (=0.03/2.51) 0.74 (=0.04/0.05)

Scenario 3B - Alternative 10 ppmv 10 ppmv

Performance Level 2WGS 90% (10ppmv) 2DGS 90% (10 ppmv) 

Emission Reductions (tpd) 0.176 0.24 

Cost Effectiveness ($/ton) 5,487 19,942 

BARCT 0.05 lbs/ton glass 0.05 lbs/ton clinker

BARCT/Start EF 0.02 (=0.05/2.51) 1 (=0.05/0.05)

Not use in 2005Not use in 2005Not use in 2005

Glass Plant Cement Plant

($

red

the 

Co

(in

fo

co
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 130 November 2, 2010 

12.2 Cost-Effectiveness Analysis Using NEC’s Estimates 

In March 2010, staff contracted with NEC, Inc. to conduct a refinery walkthrough in an effort to 

resolve any pending issues not addressed by the previous consultants and to review the 

feasibility and costs estimated by ETS/AEC and NEXIDEA. NEC provided a review of the 

capital costs and annual operating costs only, and recommended that staff re-estimate the cost 

effectiveness of the project. Staff’s estimates using NEC’s recommendations are summarized 

below.

Fluid Catalytic Cracking Units 

NEC’s estimates of capital costs for five new wet gas scrubbers at the refineries were: 

• $60,823,000 for Refinery #1 (approximately 1% higher than ETS’s estimate) 

• $94,281,000 for Refinery #2 (approximately 6.6% lower than ETS’s estimate) 

• $89,953,000 for Refinery #3 (approximately 16% higher than ETS’s estimate since NEC 

included $1.88 million for additional PM10 control. If NEC did not include the $1.88 

million for additional PM10 control which would not be required under the proposed rule, 

staff estimated the total capital costs for Refinery #3 would be $83,028,000 by using NEC’s 

approach, NEC’s multipliers for vendor bias factor, and equipment budget factor, and NEC’s 

estimates for piping, ductwork, knife gate valves, insulation etc.) 

• $66,670,000 for Refinery #4 (approximately 1.4% higher than ETS’s estimate) 

• $83,164,000 for Refinery #6 (approximately 4.4% lower than ETS’s estimate) 

NEC recommended that the maintenance costs should be about 0.6% of the capital costs. 

Turnaround occurs every 5 years, and during this period, NEC estimated that the maintenance 

costs should be double the regular maintenance costs. Staff adjusted the maintenance costs in 

ETS/AEC’s analyses to reflect NEC’s recommendation. An example of staff’s approach is 

provided below: 

Example for Refinery #1: 

Maintenance costs = (Capital costs by NEC)(0.6/100) = ($60,823,000)(0.6/100) = $364,938 

Annual costs = $1,050,951 (by ETS) - 156,000 (maintenance costs estimated by ETS) + 

$364,938 (maintenance costs recommended by NEC) = $1,259,889 

Staff then estimated the Present Worth Values (PWV) and Cost Effectiveness (CE) using NEC’s 

capital costs and annual operating costs. An example is given below for Refinery #1. The PWV 

and CE for the 5 refineries are summarized in Table 12-2. 

PWV = Capital Costs + (15.62)(Annual Operating Costs) – (0.35)(Salvage Value)67 + (2.4) 

(Maintenance Costs Every 5 Years) = $60,823,000 + (15.62)(1,259,889) – (0.35)(250,000) + 

(2.4)(364,938) = $81,290,817 

CE = ($81,290,817)/((211.82 tpy)(25 years)) = $15,351 per ton 

 

67 Salvage value is value of the control equipment at the end of its useful life (after 25 years). 
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 131 November 2, 2010 

TABLE 12-2 

Cost Effectiveness of Wet Gas Scrubbers for FCCUs using NEC’s Data 

Ref #1 Ref #2 Ref #3 (note) Ref #4 Ref#6 

Capital Costs ($) 60,823,000 94,281,000 83,028, 000 – 

89,953,000 

66,670,000 83,164,000 

Annual Operating Costs ($) 1,259,889 $2,492,288 1,457,776 – 

1,499,326 

1,058,782 1,603,872 

Present Worth Values ($) 81,290,817 126,253,530 106,906,571 

– 

114,580,302 

84,080,722 109,333,879

Cost Effectiveness ($/ton) 15,351 72,393 41,292 – 

44,2567

45,1210 12,7832

Note: the low numbers in the range are for WGS without additional PM10 control capability, and the high numbers 

are for WGS with additional PM10 control capability 

Sulfur Recovery/Tail Gas Units 

NEC’s estimates of capital costs for WGSs were: 

• $49,100,000 for Refinery #2 (approximately 29% higher than ETS’s estimate) 

• $58,210,000 for Refinery #6 (approximately 13% higher than ETS’s estimate) 

NEC’s indicated that the oxidation catalyst technology has not yet been proven in practice. NEC 

recommended wet gas scrubber as BARCT for SRU/TGs. However, if the oxidation catalyst 

technology was selected, the capital costs would increase by a factor of at least 5 versus 

ETS/AEC’s estimates, or $63,416,089 for Refinery #3. NEC estimated that the maintenance 

costs should be about 0.6% of the capital costs. Turnaround occurs every 5 years, and the 

maintenance costs should be double the regular maintenance costs in these years. Staff adjusted 

the maintenance and annual operating costs in ETS/AEC’s analyses to reflect NEC’s 

recommendation. An example of staff’s approach is provided below. 

Example for Refinery #2: 

Maintenance costs = (Capital costs by NEC)(0.6/100) = ($49,100,000)(0.6/100) = $294,600 

Operating costs = $1,446,727 (by ETS) - 48,000 (by ETS) + $294,600 (by NEC) = $1,693,327 

Table 12-3 summarizes the results for SRU/TGs. 

TABLE 12-3 

Cost Effectiveness of Controls for SRU/TGs using NEC’s Recommendations 

Ref #2 Ref #3 Ref #6 

Capital Costs ($) 49,100,000 63,416,089 58,210,000 

Annual Operating Costs ($) 1,693,327 570,859 3,305,106 

Present Worth Values ($) 76,151,815 73,229,787 110.463,974 

Cost Effectiveness ($/ton) 49,626 55,270 41,5643
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 132 November 2, 2010 

Cement Kilns & Coal Fired Boilers 

NEC recommended wet gas scrubber as BARCT for both cement kilns and coal fired boiler but 

did not provide any cost estimates for wet gas scrubbers. NEC commented that ETS’s analysis 

did not include contingencies. With contingencies added as recommended by NEC, the capital 

costs were estimated as: 

• $32,700,000 for cement kilns (approximately 67% higher than ETS’s estimate) 

• $10,300,000 for coal fired boiler (approximately 67% higher than ETS’s estimate) 

NEC estimated that the maintenance costs should be higher for cement kilns, increased from 

$312,000 as estimated by ETS to $467,000, and turnaround would occur every 2 years instead of 

every 5 years. Staff estimates of the cost effectiveness using NEC’s input are provided the 

results in Table 12-4. 

TABLE 12-4 

Cost Effectiveness of Controls for Cement Facility using NEC’s Recommendations 

Cement Kilns Coal Fired Boiler 

Capital Costs ($) 32,700,000 10,300,000 

Annual Operating Costs ($) 1,633,250 $385,293 

Present Worth Values ($) 62,086,085 17,498,910 

Cost Effectiveness ($/ton) 26,82427,402 5,312 

Glass Furnaces 

NEC recommended the use of a large bore, open throat wet gas scrubber as BARCT for glass 

furnaces instead of packed-bed wet gas scrubber. NEC recommended a different location than 

ETS which results in an increase in the costs for ducting, substation additions, knife gate valve, 

and indirect costs. While NEC did not propose cost estimates for a large bore, open throat WGS, 

NEC agreed with ETS that wet gas scrubber would be cost effective. Without any cost 

information from NEC, staff used ETS’s data instead. 

Sulfuric Acid Plants 

NEC agreed that wet gas scrubber should be recommended as BARCT for sulfuric acid plants, 

but estimated the following capital costs: 

• $18,746,000 for Plant 1 (3 times higher than ETS’s estimate) 

• $1,500,000 for modification of Plant 2 at a refinery (3 times higher than ETS’s estimate) 

NEC recommended a turnaround every 5 years for sulfuric acid plants, and an additional 

maintenance cost of 0.6% capital costs. Following NEC’s recommendations, staff estimated the 

cost effectiveness shown in Table 12-5. 
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 133 November 2, 2010 

TABLE 12-5 

Cost Effectiveness of Controls for Sulfuric Acid Plants using NEC’s Recommendations 

Plant 1 Plant 2 Modification 

Capital Costs ($) 18,746,000 1,500,000 

Annual Operating Costs ($) 684,092 $71,610 

Present Worth Values ($) 29,701,459 2,640,148 

Cost Effectiveness ($/ton) 2,8333,255 8,768 

Coke Calciner 

NEC recommended wet gas scrubber as BARCT for coke calciner, estimated a capital cost of 

$45,700,000, recommended every 2 years turnaround for the unit, and maintenance cost of 0.6% 

capital costs. Based on NEC’s recommendations, staff estimated the cost effectiveness shown in 

Table 12-6: 

TABLE 12-6 

Cost Effectiveness of Controls for Coke Calciner Using NEC’s Recommendations 

Capital Costs ($) 45,700,000 

Annual Operating Costs ($) 734,188 

Present Worth Values ($) 58,857,089 

Cost Effectiveness ($/ton) 23,036 

12.3 Comparison of Costs and Cost-Effectiveness 

In calculating the overall cost effectiveness using NEC’s data for the project, staff 1) excluded 

cost-ineffective scenarios (cost effectiveness more than $50,000 per ton emission reduced), and 

2) excluded the scenarios where emission targets already had been met. 

Present Worth Values (million dollars) = (81.29+114.58+84.08+109.33) for FCCUs + 

(76.15+110.46) for SRU/TGs + 58.86 for coke calciner + (2.64+29.70) for sulfuric acid + 8.83 

for glass + 62.1 for cement kilns = 389.29 + 186.62+58.86+ 32.34 + 8.83 + 62.09 

= $738 million. 

Emission Reductions (tons per day) = (0.58+0.28+0.20+0.94) for FCCUs + (0.17+0.29) for 

SRU/TGs + 0.28 for coke calciner + (0.03+1) for sulfuric acid + 0.19 for glass + 0.25 for cement 

= 2.01 + 0.46 + 0.28 + 1.03 + 0.19 + 0.25 = 4.22 tpd 

Cost Effectiveness = 738.02 millions / (4.22 tpd x 365 days per year x 25 years) = $15,516 per 

ton SOx reduced = $19 K per ton

A comparison between the total present worth values estimated by ETS/AEC, NEXIDEA and 

staff’s estimates based on NEC’s recommendations is shown in Tables 12-7 and 12-8. 
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 134 November 2, 2010 

TABLE 12-7

Comparison of Costs for Scenario 3A of Staff’s Proposal 

 ETS/AEC and NEXIDEA Norton Engineering (NEC) 

Equipment 

Category 

Proposed 

Standard 

(ppmv) 

Emission 

Reductions from 

2005 Baseline (tpd) 

Present Worth 

Values 

($ Million) 

Emission 

Reductions 

(tpd) 

Present 

Worth Values 

($ Million) 

Sulfuric Acid 10 1.03 19 1.03 32.34 

Glass 5 0.19 8.83 0.19 8.83 (as ETS) 

Calciner 10 0.28 25.3 0.28 58.86 

Cement 5 0.25 43.7 0.25 62.09 

FCCU 5 2.01 359 2.01 389.28 

SRU/TG 5 0.60 174 0.45 186.61 

Total 4.36* 629.83 4.21 738.02 

*The total emission reductions from 2005 baseline are 5.36 tons per day which include the 1.00 tons per day early 

reductions already in place for FCCU to meet R1105.1 requirement and SRU to meet other regulatory requirement. 

TABLE 12-8 

Comparison of Cost Effectiveness for Scenario 3A of Staff’s Proposal 

Equipment 

Category 

Proposed 

Standard 

(ppmv) 

Cost Effectiveness and 

Cost Effectiveness Range 

($/ton) 

Based on ETS/AEC/NEXIDEA 

Cost Effectiveness and 

Cost Effectiveness Range 

($/ton) 

Based on Input from NEC 

Sulfuric Acid 10 2,016 

(1,896 – 5,556) 

3,431 

(2,8333,255 – 8,768) 

Glass 5 5,198 5,198 (ETS’s estimate) 

Coke Calciner 10 9,902 23,036 

Cement 5 19,300 27,402 

FCCU 5 19,652 

(12,849 – 42,103) 

21,271 

(12,782 – 45,120) 

SRU/TG 5 31,455 

(12,880 – 39,000) 

44,514 

(41,563 – 49,626) 

Weighted Average 15,845 19,199 

The analyses above indicated that the overall costs and cost effectiveness recalculated based on 

input from are within +20% of ETS/NEXIDEA’s estimates. Staff concluded that ETS Inc. and 

NEXIDEA’s estimates are valid. 

12.4 Cost Effectiveness for Scenario 4 and Scenario 5 

Scenario 4 – In this scenario, as shown in Table 12-9, SRU/TG will not be subject to new 

BARCT: 

Present Worth Values using ETS/AEC and NEXIDEA’s costs = $455.83 million 

Emission reductions = 3.76 tons per day 

Cost effectiveness = $13.29 K per ton ($16 K per ton if using NEC’s data) 
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 135 November 2, 2010 

TABLE 12- 9

Costs and Cost Effectiveness for Scenario 4

Equipment 

Category 

Proposed 

Standard 

(ppmv) 

Emission Reductions 

from 2005 Baseline 

(tpd) 

Present Worth Values 

($ Million) 

Sulfuric Acid 10 1.03 19 

Glass 5 0.19 8.83 

Calciner 10 0.28 25.3 

Cement 5 0.25 43.7 

FCCU 5 2.01 359 

SRU/TG N/A 0.00 0.00 

Total 3.76* 455.83 

*One ton per day reduction from 2005 baseline is already in place for an FCCU and a SRU/TG 

Scenario 5 – In this scenario, as shown in Table 12-10, there will be no BARCT for SRU/TGs, 

FCCUs, and cement kilns. This scenario is intended to mimic the reduction estimated in the 

2007 AQMP. The emission reductions of 1.5 tpd from 2005 is equivalent to approximately 3.23 

tpd RTC reductions due to the unused RTCs available in the market (1.5 tpd emission reductions 

+ 1.73 tpd unused RTCs = 3.23 tpd) 

Present Worth Values using ETS/AEC and NEXIDEA’s costs = $53.13 million 

Emission reductions = 1.50 tons per day 

Cost effectiveness = $3.88 K per ton ($7.31 K per ton if using NEC data) 

TABLE 12- 10 

Costs and Cost Effectiveness for Scenario 5 

Equipment 

Category 

Proposed 

Standard 

(ppmv) 

Emission Reductions 

from 2005 Baseline 

(tpd) 

Present Worth Values 

($ Million) 

Sulfuric Acid 10 1.03 19 

Glass 5 0.19 8.83 

Calciner N/A 0.28 25.3 

Cement N/A 0.00 0.00 

FCCU Tier 1 0.00 0.00 

SRU/TG N/A 0.00 0.00 

Total 1.50 53.13 

*One ton per day reduction from 2005 is already in place for an FCCU and a SRU/TG 
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 136 November 2, 2010 

12.5 Incremental Cost Effectiveness 

To assess the incremental cost effectiveness as required under H&SC §40440.11, staff proposal 

is compared to the most stringent proposal proposed by the consultants. Comparing the 

consultants’ proposal (including modifications for fuel gas treatment system) and staff’s current 

proposal (not including modifications for fuel gas treatment system), the cost attributed to an 

additional 1.17 tpd incremental emission reductions was $377 million, which translated to an 

incremental cost effectiveness of $35K per incremental ton SOx reduced. 68 This 

significantly high level of incremental cost between the two options was the driving force 

leading staff to select the BARCT levels in Scenario 3. In staff assessment, the BARCT levels 

in Scenario 3 seeks to optimize the efficacy of the staff proposal - maximizing emission 

reductions and balancing the requirements for additional controls with economic impacts. The 

BARCT levels in Scenario 3 finally reflect “... 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.” as required by California Health and Safety (H&S) 

Code §40406. 

12.6 Comparison of Cost Effectiveness to Other Rules Adopted 

by the Governing Board 

The weighted average cost effectiveness of staff’s proposal is approximately $15K - $19K per 

ton of SOx reduced, or equivalent to $1K - $1.3K per ton NOx reduced, or $10K – $13K per ton 

PM2.5 reduced. 69 

The cost effectiveness factors should only be used as a relative measurement for comparison. 

Table 12-311 shows a comparison between the cost effectiveness derived for the 2009 SOx 

RECLAIM to the cost effectiveness of the 2005 NOx RECLAIM and other command-andcontrol rules. 

As shown in this table, controlling SOx to the BARCT levels proposed by staff would result in 

cost effectiveness which mostly falls within, or lower than, the range of the rule cost 

effectiveness approved by the Governing Board in the past. 

 

68 Incremental cost effectiveness = (1,007 – 630) million dollars / ((6.53 – (6.20 - 0.85)) tpd x 365 days per year x 

25 years) = $ 35,312 per ton. 

69 Staff used the following equivalency factor: 1 ton of SOx reduced will have the same effect as 15 tons of NOx 

reduced, or 1.5 tons of PM2.5 reduced (Appendix C of CARB’s 2007 SIP Submittal.) 
Final Staff Report – Part 1 Chapter 12 – Costs & Cost Effectiveness Analysis 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 137 November 2, 2010 

TABLE 12-311

Cost Effectiveness Comparison 

2009 SOx RECLAIM ($/ton SOx reduced) Command-Control SOx Rule 

Sulfuric acid plant: $2K per ton SOx reduced 

Glass melting furnace: $5K per ton SOx reduced 

Coke calciner: $10K per ton SOx reduced 

FCCUs: $20K per ton of SOx reduced 

Cement kilns: $19K per ton SOx reduced 

SRU/TGTUs: $26K per ton of SOx reduced 

Project Overall: $13K per ton SOx 

Flares: $5K - $9K per ton of SOx reduced (Rule 

1118 amended 11/4/05) 

2009 SOx RECLAIM ($/equivalent ton NOx reduced) (1) 2005 NOx RECLAIM 

Sulfuric acid plant: $133 per ton NOx reduced 

Glass melting furnace: $333 per ton NOx reduced 

Coke calciner: $700 per ton NOx reduced 

FCCUs: $2K per ton NOx reduced 

Cement kilns: $2K per ton NOx reduced 

SRU/TGTUs: $3K per ton NOx reduced 

Project Overall: $1K per ton NOx reduced 

Metal melting/heat treating and miscellaneous 

combustion: $4K – $11K per ton of NOx 

reduced 

Industrial boilers: $9K - $10K per ton 

FCCUs, refinery boilers/heaters: $11K-$17K per 

ton 

2009 SOx RECLAIM ($/equivalent ton PM2.5 reduced) (1) Command-Control PM Rules 

Sulfuric acid plant: $1K per ton PM2.5 reduced 

Glass melting furnace: $3K per ton PM2.5 reduced 

Coke calciner: $6.5 K per ton PM2.5 reduced 

FCCUs: $13K per ton PM2.5 reduced 

Cement kilns: $12K per ton PM2.5 reduced 

SRU/TGTUs: $17K per ton PM2.5 reduced 

Project Overall: $9K per ton PM2.5 reduced 

FCCUs: $13K-$23K per ton filterable PM, $3-

$5K per ton filterable and condensable (Rule 

1105.1, adopted 11/7/03) 

Coke/Coal/Sulfur Handling: $3-$30K per ton 

PM10 (Rule 1158, amended 6/11/99) 

1) The comparison in this table uses the following equivalency: of 1 ton of SOx reduced has an equivalent effect to 15 tons of 

NOx reduced, or 1.5 tons of PM2.5 reduced provided in Appendix C to CARB’s 2007 SIP Submittal. 
Final Staff Report – Part I Chapter 13 – RTC Reductions & Implementation 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 138 November 2, 2010 

Chapter 13 – RTC Reductions & Implementation 

13.1 RTC Reductions Estimated from 1997 Baseline 

Staff applied the same methodology used for NOx RECLAIM to estimate the projected year 

2019 SOx emissions for the entire SOx RECLAIM universe as follows: 

Projected Emissions at New BARCT Levels = (1997 Baseline x Growth Factor2019) x New 

BARCT Adjustment Factor (or Tier 1, if no new BARCT is recommended) 

Where: 

Projected Emissions at New BARCT Levels = Emissions in year 2019 at new BARCT levels. 

1997 Baseline =Actual emissions from July 1, 1997 – June 30, 1998. 70

Growth Factor2019 = Growth factor from 1997 – 2019 for each facility 

New BARCT Adjustment Factor = New BARCT Emission Factor / Starting Emission Factor (in 

Table 2 of Rule 2002) 

Staff applied the 10% upward adjustment factor to the 2019 projected emissions at new BARCT 

levels, and calculated the year 2019 RTC reductions for each of the scenarios described in 

Chapter 13 as follows: 

Programmatic RTC Reductions = 11.77 - [Projected Emissions at New BARCT Levels x 10% 

Compliance Margin] 

 

 Where: 

Projected Emissions at New BARCT Levels = Remaining emissions of the entire SOx 

universe in year 2019 

 

The entire SOx RECLAIM universe was captured in this approach. In this approach, it was 

assumed that the year 1997 emission rates were similar to the starting emission factors. Staff 

estimated the projected remaining 2019 emissions, the RTC reductions and the percent 

reductions for the scenarios outlined in Chapter 12: Scenario 1 represented the impacts of the 

most stringent control measures, Scenario 2 represented the impacts based on the consultants’ 

recommendations, Scenario 3A reflected staff’s recommendations, Scenario 3B and Scenario 4 

are alternatives to staff’s proposal, and the last Scenario 5 is to get the minimum of 3 tons per 

day reductions. The RTC reductions for Scenario 3A, 4 and 5 are summarized in Table 13-1. 

Scenarios 1 and 2 will result in more than 70% RTC reduction, and Scenario 3B will result in 

approximately the same shave as Scenario 3A. 

 

70 In this analysis, staff used the actual CEMS reported emissions from July 1, 1997 – June 30, 1998. The period 

used in the 2003 AQMP is from July 1, 1996 – June 30, 1997. According to the RECLAIM Annual Audit Reports 

based on the CEMS data, the inventory for the compliance year 1996 was 6,484 lbs (17.76 tpd), and the inventory 

for the compliance year 1997 was 6,464 lbs (17.71 tpd). Since there is very little difference between the two 

inventories, staff believes that the results presented here, even for the 1997-1998 period, would reflect the 1996-

1997 period as well. 
Final Staff Report – Part I Chapter 13 – RTC Reductions & Implementation 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 139 November 2, 2010 

As a result of the current BARCT analyses, staff proposal is to reduce the RTC holdings by 6.14 

tons per day (55% reduction of the current 11.77 tons per day RTC holdings) to ensure that the 

SOx market incentive program will “achieve an equivalent or greater level of emission 

reductions at an equivalent or lower cost as would have been achieved under a command-andcontrol rule” as required by California H&S Code §39616. 

In addition, staff proposes a eight-year implementation program to get 6.1 tpd RTC reduction: 

• 1.5 tons per day reductions in Compliance Year 2012 

• 1.5 tons per day reductions in Compliance Year 2013 

• 1.5 tons per day reductions in Compliance Year 2014 

• 0.32 ton per day reductions in Compliance Year 2015 

• 0.32 ton per day reductions in Compliance Year 2016 

• 0.32 ton per day reductions in Compliance Year 2017 

• 0.32 ton per day reductions in Compliance Year 2018 

• 0.32 ton per day reductions in Compliance Year 2019 

The first 4.5 tons per day reduction will meet and then exceed the commitment under the 2007 

AQMP, to help the Basin achieve the federal annual average PM2.5 standard by 2014. The 

remaining reductions will help the Basin to achieve the federal 24-hour average standard by 

2020. 

It should be noted that the difference between the RTC holdings of 11.77 tons per day and the 

actual emissions of 9.22 tons per day in year 2008 is about 2.55 tons per day. This margin can 

be proven quite useful in meeting the proposed emission reductions during the initial phase of 

implementation. The remaining tons per day actual emission reductions in compliance year 

2014 and beyond must be generated by implementing additional control measures. Assuming 

the rule is adopted in 2010, a 4 to 5-year window is likely needed to implement all control 

measures recommended by staff and the consultants. The consultants estimated about 2 - 3 years 

for implementation. An additional 2 years may be needed to reconcile the turn-around for some 

refineries in the District. To ease the implementation of this large project, especially to ease 

some environmental/energy impacts that may occur, staff recommends spreading the tons per 

day RTC reductions into eight years, from 2012 to 2019. 
Final Staff Report – Part 1 Chapter 13 – RTC Re

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 140 

TABLE 13-1 - RTC Reductions Estimated From 1997 Baseline 

AQMP Method - Projected to 2019 

Equipment Type 

Audited 

97-98 

Fiscal 

tpd 

Growth 

Factor 

1997-

2019 

2019 

with 

growth 

Scenario 3 - Staff's Proposal Scenario 4 - Intermediate 

BARCT 

Adj 

Factor 

ReM ReD 

BARCT 

Adj 

Factor 

ReM ReD 

BAR

Ad

Fac

FCCUs 5.68 1.00 5.68 0.06 0.34 5.34 0.06 0.34 5.34 0.2

SRU/TG 2.03 1.00 2.03 0.63 1.28 0.75 1.00 2.03 0.00 1.0

Coke Calciner 1.31 1.00 1.31 0.05 0.07 1.25 0.05 0.07 1.25 0.0

Sulfuric Acid 1.06 1.30 1.37 0.04 0.05 1.31 0.04 0.05 1.31 0.0

Glass Melting Furnace 1.71 1.45 2.48 0.01 0.02 2.45 0.01 0.02 2.45 0.0

Cement Kilns 0.53 2.58 1.36 0.74 1.01 0.35 0.74 1.01 0.35 1.0

Boilers/Heaters 6.11 1.00 6.11 0.20 1.22 4.88 0.20 1.22 4.88 0.2

Total Major Equipment 18.42 1.10 20.33 3.99 16.34 4.74 15.59 

Others 1.06 1.11 1.18 1.18 1.18 

Total Remaining In Year 2019 With Growth (Minus 0.054 tpd reductions from R431.1 & R431.2 for AQMP Method) 

5.12 5.87 

1.1 x (Total Remaining) 5.63 6.45 RTC Reduction in Yr 2019 w 1.1 Factor = 11.77 - (1.1xTotal Remaining) 6.14 5.32 For alternative shave, % reduction w 1.1 = (shave/11.09) 55% 48% RTC Reduction in Year 2019 w/o 1.19 Factor = 11.77 - (1.19*Remaining) % Reduction Across Universe w/o 1.1 to compare w AQMP = (shave/11.78) 
Final Staff Report – Part 1 Chapter 13 – RTC Reductions & Implementation 

__________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 141 November 2, 2010

 

13.2 Alternative Shave 

As a result of staff’s analysis in Section 13.1, the overall proposed shave is approximately 52% 

across the 32 facilities in the SOx universe. Staff received comments from the 22 facilities with no 

equipment subject to new BARCT indicating that the uniform shave was not equitable, and would 

create significant difficulties for them to stay in compliance, and indicated that they had limited 

ability to buy RTCs from large facilities 

Because of the non-uniform characteristics (actual emissions and RTC distributions) of the SOx 

RECLAIM market (11 major facilities hold 87% RTCs and contribute more than 90% of emissions, 

and the remaining 21 facilities hold only 6% RTCs and contribute about 7% of emissions), uniform 

percent shave across the board is not the ultimate solution. The 21 facilities that have no equipment 

subject to the new BARCT cannot reduce their emissions further and cannot sustain operation and 

remain in compliance after the shave. To keep the 21 facilities active in the SOx market, staff is 

proposing to not shave the RTC holdings for these facilities if the RTC holdings are below their initial 

allocations provided to these facilities at the start of the RECLAIM program. However, the amount 

of RTC holdings above their initial allocations will be shaved at the same rate as other 11 facilities 

and investors. With this approach, staff estimated that instead of shaving across the board, the 11 

facilities will have a shave of 55%, 18 of the 21 facilities will be exempt totally from the shave, and 3 

of the 21 facilities that have RTC holdings above their initial allocations will be shaved to the initial 

allocation levels. Any traded RTCs from August 29, 2009 to the date of adoption will also be shaved 

at the rate of the 11 facilities. 

The results of this analysis are presented in Table 13-2 

13.3 RTC Reductions Estimated from 2005 Baseline 

One of the elements included in the Work Plan presented to our Governing Board in January 2010 is 

the commitment for staff to work closely with the Western States Petroleum Associations (WSPA) 

and its members in evaluating its alternative proposal. Staff held numerous meetings with WSPA and 

its members on this subject. As part of its proposal, on July 30, 2010, WSPA and the refineries 

proposed the 2005 baseline to be used to estimate the RTC reductions arguing that the 2005 baseline 

has been used to estimate cost effectiveness by the consultants and the 2005 emissions represent the 

most current emission profile for SOx RECLAIM. In addition, WSPA and its members proposed to 

exclude RTCs converted from ERCs (1.98 tons per day) from any future shave. WSPA’s proposal 

was obscure and did not show how the RTC reductions were related to actual emission reductions 

estimated from the 2005 baseline. It seems that WSPA’s position was to treat RTC reductions as 

equivalent to actual emission reductions, ignoring the surplus RTCs in the market. Before July 2010, 

WSPA proposed a 25% shave characterized as an emission reduction shave. On August 18, 2010, 

WSPA revised its proposal agreeing to 33% shave (3.9 tpd) across the board by the end of 2019. On 

September 16, 2010, WSPA again revised its proposal agreeing to 40% shave (4.7 tpd) across the 

board by the end of 2019. 71 In order to fully understand WSPA’s proposal and provide meaningful 

 

71 WSPA’s presentation to staff on July 30, 2010 and August 18, 2010; WSPA’s proposal to Barry Wallerstein on 

September 16, 2010; and WSPA’s presentation at the Refinery Committee Meeting on September 22, 2010. 
Final Staff Report – Part 1 Chapter 13 – RTC Reductions & Implementation 

__________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 142 November 2, 2010

 

comments to WSPA, staff contacted WSPA several times since July 30 to ask for an explanation on 

its methodology, specifically how to calculate the percent shave and RTC reductions from actual 

emission reductions. Unfortunately, WSPA offered very limited explanation to staff. To keep the 

project moving in a positive direction, staff provides the following initial comments on WSPA’s 

proposal. 

SOx RECLAIM started in 1993 and the initial allocations (or RTCs) provided to the RECLAIM 

facilities were ample, generally more than the amount that they emitted. The surplus of RTCs in 2005 

is about 1.73 tons per day and the surplus of RTCs in 2008 is about 2.55 tons per day. The amount 

RTCs converted from ERCs contributed to the size of the surplus. For the RECLAIM facilities to 

actually install BARCT and reduce “real” emissions, the surplus RTCs must be removed. RTCs 

reflect the “Potential to Emit” and thus even though RTCs carry the same unit (i.e. in lbs SOx) as 

actual emissions, they represent different “currencies” than actual emissions. To fully demonstrate 

command-and-control equivalency due to the implementation of BARCT, due to the surplus, the 

amount of RTC reductions should be more than the amount of actual emission reductions and the 

percent reduction estimated using RTCs should be higher than the percent reduction estimated using 

actual emission reductions. 

It seems that the proposal by WSPA and its members calls for the calculation of the percent shave by 

taking the ratio of the actual emission reductions estimated off the 2005 baseline emissions over the 

RTCs held in the market excluding any RTC converted from ERCs (1.98 tpd) at the inception of the 

RECLAIM program for which WSPA argued that should be excluded from any future shave. Staff 

acknowledges that the 2005 year emissions were used as a baseline by the consultants to formulate 

their recommendation on feasibility and cost of controls because they reflected the most recent year 

emission profile available at the time. However, dividing the “emission reductions” estimated off the 

2005 baseline by the RTCs to derive the percent reduction amounts to using two different 

“currencies” to compute a percent figure. This approach will not yield a result that can be used to 

demonstrate equivalency to command-and-control. Staff uses the “remaining emissions”, a constant 

currency, to calculate the amount of shave and to compare with a command-and-control program. 

Furthermore, WSPA and the refineries proposed to exclude RTCs converted from ERCs (1.98 tons 

per day) from any future shave which is inconsistent with the RECLAIM program. As explained 

above, the RTCs converted from ERCs (1.98 tons per day) is a layer of cushion added to the surplus. 

Integrating the shave through this layer of surplus is one of the RECLAIM approach since the start of 

the program in 1993. The RTCs converted from ERCs were shaved approximately 35% from Tier 1 

to Tier 2 to match AQMP emission budgets for the RECLAIM program. It was clearly the Board’s 

policy to achieve programmatic equivalency with command & control without providing a special 

status to ERC converted to RTCs. When NOx program was shaved in 2005, ERCs converted to 

RTCs were treated the same as regular RTCs. Future economic growth was included in the emission 

projection. The RTCs converted to ERCs have also been used by many of the RECLAIM facilities in 

lieu of their emission reductions requirements under Tier 1 BARCT, which is not allowed for nonRECLAIM facilities. Therefore, it would be appropriate to include these RTCs in the future shave, 

retain equivalency with command and control, and attain the air quality objectives of the region. In 

addition, for non-RECLAIM facilities, the emissions from shutdown equipment are required to be 

discounted to BACT level, before ERCs can be issued. Furthermore, new or modifying nonRECLAIM facilities undergoing New Source Review (NSR) are required to offset any emission 

increase for SOx and NOx by a 1.2 to 1.0 ratio. On the other hand, RECLAIM facilities undergoing 
Final Staff Report – Part 1 Chapter 13 – RTC Reductions & Implementation 

__________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 143 November 2, 2010

 

NSR are not subject to the 1.2 to 1.0 offset ratio that non-RECLAIM facilities are. The following 

table summarizes the comparison between ERC generation and use between RECLAIM and nonRECLAIM program. Considering all of the above facts plus the benefits incurred by the RECLAIM 

facilities utilizing such RTCs during the 17-year life of the program since 1993, staff believes that the 

1.98 tons per day RTCs converted from ERCs do not deserve a special status, and thus the 1.98 tons 

per day RTCs converted from ERCs, which add to the RTC surplus, should be subject to the future 

RTC shave of 55%. In summary: 

 Non-RECLAIM RECLAIM 

Usable in lieu of BARCT Yes No 

BACT Discount No Yes 

Offset Ratio 1.2 to 1.0 Yes No 
Final Staff Report – Part 1 Chapter 13 – RTC Re

____________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 144 

TABLE 13-2 – Shave Adjustment Factors for Staff’s Proposal – 55% Shave in 2019 

Year 2012 RTC Inventory as of August 29, 2009

11 major 21 others investors total

10.21 0.73 0.83 11.77

Estimation of Adjustment Factors for Rule 2002

RTC subject to shave for

11 major facilities, 3 of

the remaining 21

facilities, and investors

RTC Non‐Shaved

Portion

RTC Reduction

for the following

year

RTC for Shave Adjustment Fac

for next yea

Start Year 2011 11.09 0.68 11.09 

End Year 2011 1.5 11.09‐1.5=9.59 9.59/11.09=0.8

Start Year 2012 11.09x0.865=9.590 0.68 9.59 

End Year2012 1.5 9.59‐1.5=8.09 8.09/11.09=0.7

Start Year 2013 11.09x0.729=8.090 0.68 8.09 

End Year 2013 1.5 8.09‐1.5=6.59 6.59/11.09=0.5

Start Year 2014 11.09x0.594=6.590 0.68 6.590 

End Year 2014 0.32 6.59‐0.32=6.27 6.27/11.09=0.5

Start Year 2015 11.09x0.565=6.27 0.68 6.270 

End Year 2015 0.32 6.27‐0.32=5.95 5.95/11.09=0.5

Start Year 2016 11.09x0.537=5.96 0.68 5.960 

End Year 2016 0.32 5.96‐0.32=5.635 5.635/11.09=0.

Start Year 2017 11.09x0.508=5.635 0.68 5.635 

End Year 2017 0.32 5.635‐0.32=5.315 5.315/11.09=0.

Start Year 2018 11.09x0.479=5.315 0.68 5.315 

End Year 2018 0.32 5.315‐0.32=4.995 4.995/11.09=0

Start Year 2019 11.09x0.45=4.99 0.68 4.99 

End Year 2019 0

6.100

Summary

RTC HOLDINGS RTC subject to shave Non‐shaved Total

Starting 11.09 0.68 11.77

Ending (Remaining) 4.99 0.68 5.67

Reduction 6.10 0.00 6.10

% reduction 55.0% 0%

Three of 21 facilities have RTC holdings larger than initial allocations by a total of 0.05 tpd

Therefore, non‐shaved portion for 22 facilities ‐ 0.73 ‐ 0.05 = 0.68 tpd

Total reduction in 8 years (2012‐2019)

This table includes the following RTC Holdings: 10.21 tpd from 11 major facilities, 0.05 tpd from 3 of the remaining 21 facilities, and 0.83 tpd 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 145 November 2, 2010 

Chapter 14 – Comments & Responses 

Responses to WSPA’s Comments Received in Refinery Committee 

Meeting on October 14, 2010

Comment #1:

At the Refinery Committee Meeting on October 14, 2010, WSPA commented that staff is required 

by the California H&SC §40406 to estimate the cost-effectiveness numbers by each class or 

category of source, and that staff should not pre-exclude the cost-ineffective scenarios of more 

than $50,000 per ton SOx reduced in estimating the weighted average cost effectiveness for the 

project. 

Response #1

The California H&SC §40406 does not specifically dictate where in the calculation process staff 

should exclude the cost-ineffective scenarios. However, in response to WSPA’s comment, staff 

estimated the weighted average cost effectiveness for each class or category of sources

regardless of each of the individual cost-effectiveness numbers. Tables 1 and 2 below show the 

costs and cost-effectiveness for each individual class or category of sources and the overall 

weighted average cost-effectiveness for the project. The weighted average cost effectiveness for 

the project ranges between $19K per ton based on ETS/AEC and NEXIDEA data and $22K per 

ton based on NEC data (see Note 2 of Table 1) and does not alter staff’s conclusions regarding 

proposed BARCT.

Table 1 - Present Values

ETS/AEC and NEXIDEA Norton Engineering (NEC)

Equipment 

Category

Proposed 

Standard

(ppmv)

Emission 

Reductions 

(tpd)

Present

Values

($ Million)

Emission 

Reductions 

(tpd)

Present 

Values

($ Million)

Sulfuric Acid 10 1.03 19 1.03 32

Glass 5 0.19 8.83 0.19 8.83 

Calciner 10 0.28 25.3 0.28 59

Cement 5 0.25 43.7 0.25 62

FCCU 5 3.07 567 3.07 590

SRU/TG 5 0.95 (note 1) 318 0.95 404 (note 2)

Total 5.76 981 5.76 1,156

Note: (1) Refinery 3 has three existing sulfur plants vented to two tail gas units. ETS/AEC recommended 

Emerachem technology for the first unit at a cost effectiveness of $12,880/ton and 0.15 tpd reductions, and a WGS 

for the second unit at a cost effectiveness of $32,109/ton and 0.12 tpd reductions. In the final report, ETS/AEC 

selected Emerachem for the first tail gas unit because it was more cost-effective than WGS for the second tail gas 

unit. In this exercise, staff included ETS/AEC’s costs for both tail gas units at Refinery 3. (2) NEC did not reestimate the costs for (i) the WGS for the second unit of Ref 3, (ii) the Emerachem for Ref 1 of which the emission 

reductions were already achieved, and the Emerachem for Ref 4, and (iii) the WGS for Ref 5 since. This task was 

not in the NEC’s contract. To complete this analysis, staff substituted ETS/AEC information for these situations in 

which NEC did not provide a cost estimate. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 146 November 2, 2010 

Table 2 – Cost Effectiveness

Equipment 

Category

Proposed 

Standard

(ppmv)

Cost Effectiveness

($/ton)

Based on ETS/AEC/NEXIDEA

Cost Effectiveness 

($/ton)

Based on Input from NEC

Sulfuric Acid 10 2,016 3,431

Glass 5 5,198 5,198

Coke Calciner 10 9,902 23,036

Cement 5 19,300 27,402

FCCU 5 20,251 21,088

SRU/TG 5 36,734 46,709

Weighted Average 18,664 21,992
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 147 November 2, 2010 

Responses to INTERCAT’s Comments Received on October 10, 

2010

Comment 

#1 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 148 November 2, 2010 

Comment 

#2 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 149 November 2, 2010 

Comment 

#3 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 150 November 2, 2010 

Response #1

Staff appreciates the commenter for informing staff that it is technologically feasible for 

INTERCAT SOxGETTER to achieve 5 ppm SOx without impacting adversely tothe FCC 

processing rates and yields or PM emissions from the refinery ESPs. Staff also appreciates the 

commenter for providing the information about the performance with INTERCAT SOxGETTER 

that 1) three refineries recently conducted short-term testing with INTERCAT Super 

SOXGETTER and all three refineries achieved 5 ppmv SO2, and 2) many other FCCUs have 

already achieved 5 ppmv demonstrated through the EPA testing protocols during the EPA 

Consent Decree testing program. Staff is in agreement with the commenter that each refiner 

should conduct short term testing to measure the performance of INTERCAT SOxGETTER (or 

Super SOxGETTER) prior to long term use. A short term testing was conducted at a refinery in 

the District in 2008, and during a three-month testing period, the refinery showed that their 

FCCU could achieve 7 ppmv SOx at about 6% - 7% catalyst addition rate without negative 

impacts to FCC processing rates, FCC yields, or PM emissions. Since this was a short-term 

testing and there were no legal requirements to achieve 5 ppmv, the refinery stopped the testing 

at 7 ppmv. Had this refinery continued the testing process, it would very likely demonstrate the 

proposed BARCT standard 5 ppmv level at a slightly higher addition rate than 6%-7%. 

Furthermore, staff acknowledges that ammonia and SO3 can be used to reduce the resistivity of 

particulate matters and enhance the capture of particulate matters in the ESPs. However, please 

note that SCAQMD Rule 1105.1 contain two standards: (1) a filterable PM10 standard of 0.005 

grain per dry standard cubic foot of flue gas corrected to 3% O2 dry (or 3.6 lbs pounds per hour, 

or 2.8 pounds per thousand barrels of fresh feed); and (2) an ammonia slip standard of 10 ppmv, 

corrected to 3% O2 dry, averaged over 60 consecutive minutes. The ammonia slip standard is to 

minimize the condensable particulate emissions from the FCCU. Therefore, using ammonia in 

the ESPs which results in a slip of more than 10 ppmv ammonia is not allowed. Staff would 

highly encourage the manufacturers of SOx reducing additives to continue their research to 

identify ways to reduce the resistivity of SOx reducing additives at the molecular level, and thus 

help optimizing the collection of the used catalysts in the ESPs, and minimizing the use of toxic 

enhancers such as ammonia in the ESPs.

 

Response #2

The definition #72 in Rule 2000 – General, amended May 6, 2005, states that “SOx EMISSIONS 

means sulfur dioxides emitted.” The BARCT level of 5 ppmv proposed by this rule is based on 

an annual average (i.e. averaged over 365 days of a compliance year. The compliance year for 

Cycle 1 facilities is from January 1 to December 31, and for Cycle 2 facilities is from June 1 to 

July 31.) The facility operator is not required to meet the “equipment-BARCT” level, equipment 

by equipment, however the facility is required to meet the “programmatic-BARCT” level, which 

means that the facility must comply with the annual facility cap (and RTC reductions), 

determined based on the equipment-BARCT level, by the end of the reconciliation period of any 

compliance year. 

Staff does not propose a SOx limit for excursions. Excess emissions during these excursions 

may be excluded in determining compliance with the facility’s annual cap if the facility meets all 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 151 November 2, 2010 

the requirements specified under Rule 2004(i). The facility operator must be in compliance with 

the annual facility cap by the end of the reconciliation period of any compliance year.

Response #3

Staff appreciates the information provided by the commenter on the benefits of using SOx 

reducing catalysts. Staff is in agreement with the commenter that there are many benefits of 

using SOx reducing additives: 1) The refineries can use additives virtually immediately to 

reduce the SOx emissions from their FCCUs; 2) no additional plot space is required; 3) no 

increase in water consumption; 4) no steam plume; and 5) no increase in energy used and GHG 

associated with the use of SOx reducing additives.

Regarding the costs and cost-effectiveness, using SOx reducing catalysts will reduce capital 

expenditures but not necessarily annual operating costs. Staff estimates on costs and costeffectiveness for SOx reducing catalysts and WGSs are provided in Chapter 12 of the Staff 

Report.72 The weighted average cost-effectiveness for WGS to achieve 5 ppmv is approximately 

$20K per ton (average of 4 refineries that can cost-effectively install WGSs) and the weighted 

average cost-effectiveness for SOx reducing catalysts is approximately $19K per ton (average of 

5 refineries that can cost-effectively use additional SOx reducing catalysts) to achieve 7 ppmv. 

With the competitiveness of the market and the improvement of SOx reducing technology, the 

cost-effectiveness numbers for SOx reducing catalysts may improve, and the present worth 

values of using SOx reducing catalysts may amount to only half the costs for installing WGSs as 

estimated by the commenter.

It should be noted that staff does not agree with the commenter that the use of WGSs would 

orphan the significant investment that the refiners had made in the ESPs. ESPs are required to 

control PM10 emissions while WGSs are to control SOx emissions. Further explanations are 

provided in Response #1 to WSPA’s comment received from March 2010 – August 2010 under 

the topic discussing about whether or not there is stranded investment of Rule 1105.1.

In addition, staff does not agree with the commenter that the use of WGSs will convert air 

pollutant into water pollutant. Various types of absorbents (e.g. caustic or lime) can be used to 

absorb SOx and converts SOx to soluble sulfates (e.g. sodium sulfates) or non-soluble sulfates 

(e.g. calcium sulfates). These sulfates can be collected and reused, or treated and safely 

discharged to the waste water stream. As an example, the suspended solid waste and the used 

catalyst fines from a FCCU’s WGS in the District are collected and sold to a cement plant to be 

reused. 

 

72 With limited information at this time on the amount of SOx reducing catalysts needed for each FCCU, 

staff used the information from a refinery in the District that tested SOx reducing catalysts and achieved 7 

ppmv in a 3-month period in 2008 to estimate the cost-effectiveness for SOx reducing additives shown in 

Scenario 3B of Chapter 12. Please note that since this refinery did not use INTERCAT product in 2008, 

the costs of SOx reducing additives and the quantity needed may be different than those estimated by the 

commenter. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 152 November 2, 2010 

Furthermore, staff does not agree that the transportation of caustic solution would pose any new 

transportation hazards. If all five refineries would use SOx reducing additives in lieu of 

installing WGSs, the NaOH demand would be reduced from 13.24 tons per day to 8.79 tons per 

day for the SOx RECLAIM project, and as analyzed by CEQA staff, the transportation of 

additional NaOH would not pose any new transportation hazards: 73 

“All of the refineries (Facilities A through G) currently receive NaOH from local 

suppliers located in the greater Los Angeles area. For the remaining facilities that do not 

currently use NaOH, but will begin using it, the local suppliers are expected to be able to 

accommodate the additional demand. As is currently the case with existing NaOH 

deliveries, deliveries of additional NaOH would be made to each facility by tanker truck 

via public roads. NaOH is typically delivered in 6,000 gallon trucks, so the proposed 

project would not introduce any new transportation hazards for NaOH.”

 

73 SCAQMD Program Environmental Assessment, Chapter 4, August 2010. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 153 November 2, 2010 

Responses to Owens-Brockway’s Comments Received on October 

21, 2010

Comment 

#1 

Comment 

#2 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 154 November 2, 2010 

Comment 

#3 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 155 November 2, 2010 

Response #1

Based on recommendations from its two technical consultants and information from other glass 

melting furnaces elsewhere, staff concluded that Ttoday’s BARCT for container glass melting 

furnaces is 5 ppmv outlet concentration, or 95% control or more. This BARCT level is achieved 

in practice at Saint-Gobain glass container facility in Seattle, Washington. In addition, achieving

this level of BARCT is cost-effective. In an effort to determine costs, ETS provided equipment 

vendors with flue gas flow rates, inlet concentrations, and other necessary parameters. Flue gas 

flow rate is an important parameter in determining equipment size and costs for the WGS, while

inlet concentration is an important parameter in determining the amount of caustic sorbent 

needed to achieve 5 ppmv outlet SOx concentration and annual operating costs. The present 

value for two WGSs (25-year life) estimated by ETS was $8.8 million, in which the capital costs 

were $1.90 million, and the annual operating costs were $0.44 million. ETS estimated a costeffectiveness of $4,988 per ton SOx reduced. Assuming that Owens-Brockway was correct in 

stating that their inlet concentration were 200 ppmv-250 ppmv without the use of the dry 

scrubbers, and assuming that it would need roughly 3 times more caustic solution to reduce a 

stream of flue gas at 250 ppmv down to a level of 5 ppmv than to reduce from 100 ppmv to 5 

pmmv, then the present value of these two WGSs would be conservatively estimated to be $22.5 

million and the cost-effectiveness would be $12,988 per ton.74 At $12,988 per ton, it would still 

be cost-effective to control the SOx emissions from glass melting furnaces at Owens-Brockway 

to a BARCT level of 5 ppmv (95% control or more). Thus, the WGS is capable of controlling an 

exhaust stream at 250 ppm down to 5 ppm (i.e., 98% control efficiency).

Response #2

Staff’s responses to the issues raised are as follows:

• Wet gas scrubber is used to control acid gas (SOx) emissions for many decades and there 

are many types of wet gas scrubber that can reduce 95% or more of SOx emissions from 

the glass melting furnaces – either a packed bed scrubber recommended by ETS and by 

Manufacturer A, or an open-throat scrubber recommended by NEC, or a Cloud Chamber 

scrubber as installed at Saint-Gobain glass facility in Seattle.

• The purpose of SOx RECLAIM is to implement BARCT for SOx, therefore ETS and 

NEC did not discuss about “primary particulate matter” control in their analyses. 

However, SOx is a precursor to particulate, and therefore reducing SOx will reduce 

“secondary particulate matter”. Another added benefit of the ETS’s proposal is that ETS 

recommended the removal of the two dry scrubbers upstream of the ESPs. Reducing the 

Trona used in the two dry scrubbers to zero will substantially reduce the primary 

particulate loadings to the ESPs, save energy, and annual operating costs. These savings 

have not yet been factored in ETS’s estimate of cost-effectiveness. 

 

74 Present Value estimated by ETS = $1.90 million + (15.62)(0.44 million) = $8.8 million. Present Value 

where annual operating costs are 3 times higher than estimated by ETS = $1.90 million + 

(3)(15.62)(0.44)(3) = $22.5 million and Cost Effectiveness = $22.5 million/((0.19 tpd)(365)(25)) = 

$12,988 per ton. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 156 November 2, 2010 

• The commenter complains that the consultants failed to address a variety of issues. This 

is incorrect.

• Wet gas scrubbers for acid gas removal are low-energy scrubbers with pressure drop of 

about 5 in – 10 in. Removing the two dry scrubbers in front of the ESPs will compensate 

for the pressure drop across the two wet scrubbers downstream of the ESPs. 

Manufacturer D also include a fan in their equipment package to compensate for any 

potential pressure drop.

• Owens-Brockway currently has a waste water treatment at their facility. OwensBrockway discharges waste water to LACSD. The facility has a permit discharge limit 

of 250 gpm and the current discharge rate is below 100 gpm. A typical waste water 

stream from a caustic scrubber contains mostly soluble sodium sulfate.

• The costs for new stacks were included in Manufacturer D equipment costs. NEC did 

recommend ETS to add 50% contingency to cover other miscellaneous costs such as 

costs for CEMS relocation/recertification, permitting costs etc. Adding 50% contingency 

would result in a cost-effectiveness of about $5,607 per ton SOx reduced. 75 Thus WGS 

would be still be cost-effective to control emissions from a glass melting furnace.

• The consultant did not address NSR issues because they were not tasked to do so. 

However, NSR issues should not be significant since Owens-Brockway should not be 

increasing emissions due to the installation of WGS.

Response #3

Staff is committed to work with Owens-Brockway and all other impacted facilities to facilitate 

permitting and ensure the successful implementation of the staff proposal. However, NSR 

related issues are best handled during the permitting phase. Please be cognizant that while NSR 

issues related to NOx and SOx are covered in Rule 2005, NSR issues related to other criteria 

pollutants are covered in Regulation XIII. Both regulations provide that permit modifications 

that do not increase emissions do not trigger BACT.

 

75 PV = ($1.9 million)(1.5) + (15.62)(0.44) = $9.72 million, CE = ($9.72 million) / ((0.19)(25)(365)) = 

$5,607 per ton. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 157 November 2, 2010 

Responses to Owens-Brockway’s Comments Received on September 

22, 2010

Comment 

#1 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 158 November 2, 2010 

Comment 

#2 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 159 November 2, 2010 

Comment 

#3 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 160 November 2, 2010 

Comment 

#4 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 161 November 2, 2010 

Comment 

#5 

Comment 

#6 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 162 November 2, 2010 

Comment 

#6 

Comment 

#7 

Comment 

#8 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 163 November 2, 2010 

Comment 

#8 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 164 November 2, 2010 

Comment 

#8 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 165 November 2, 2010 

Comment 

#8 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 166 November 2, 2010 

Comment 

#8 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 167 November 2, 2010 

Response #1

Staff appreciates the efforts that your facility operators have made to lower SOx emissions and 

your position that BARCT for glass manufacturing should be the controls currently operating at 

your facility. However, the application of wet gas scrubbers still remains the recommended 

BARCT for glass manufacturing furnaces as explained in Response #2.

Furthermore, Owens-Brockway Glass Container Inc. (Vernon Branch) is a subsidiary of OwensIllinois, Inc. According to website for Owens-Illinois, the parent company of Owens-Brockway, 

in 2009 Owens-Illinois had 22,000 employees in 21 countries with net sales of $7.1 billion76. 

SCAQMD records confirm that Owens-Brockway is the only glass container facility in the 

District.

Response #2 

Control technology has improved over time. The dry scrubbers with 80 percent to 90 percent 

control efficiency were considered as BARCT for SOx in 1994. However, in between 2008 and 

2010, two consultants (ETS and NEC) expressed agreement that non-regenerative wet scrubbers 

can achieve 1 ppmv - 5 ppmv SOx outlet concentration (95 percent control efficiency or more 

from the 2005 emissions baseline, 99% from the uncontrolled level assuming that the dry 

scrubbers operated at 80% control) and thus, should be considered as BARCT for SOx for glass 

melting furnaces. While these two consultants recommended different types of WGSs, they both 

concurred that WGSs would be cost-effective and staff concurs with the consultants’ 

recommendations. The two consultants both recommended keeping the existing ESPs in place 

for particulate control and placing the wet scrubbers downstream of the ESPs. 

In addition, the proposed BARCT level for glass melting furnaces has been achieved in practice. 

Specifically, the Puget Sound Clean Air Agency in Seattle, Washington provided SCAQMD 

staff with source test and CEMS data from Saint-Gobain, a glass container facility, that 

demonstrates compliance with 5 ppmv SOx levels (96 percent control) via Tri-Mer’s Cloud 

Chamber scrubber. The furnace at Puget Sound has a permit limit of 1.6 pound of SOx per ton 

of glass pulled but tested at 0.0062 pounds of SOx per ton of glass pulled.77,78 Staff had multiple 

conversations with Tri-Mer about their WGS technology, and Tri-Mer indicated to staff that they 

provided many types of WGS that can be used to achieve 5 ppmv SOx outlet concentration, 

either packed bed, open throat, venturi, or Cloud Chamber scrubber. The Cloud Chamber 

scrubber can also be used as particulate control device.

 

76 O-I Announces Third Quarter Earnings Conference Calland Webcast, September 20, 2010.

 http://www.o-i.com/nth_us.aspx?id=400

77 Horizon Engineering, “Source Test Evaluation Report for Saint-Gobain, Seattle, Washington, Glass Melting 

 Furnace No. 5 with Cloud Chamber Scrubber,” September 18, 2009. 

78 CEMS Summary Report from Saint-Gobain to Puget Sound Clean Air Agency, for a period from October 1, 2009 

 to October 31, 2009. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 168 November 2, 2010 

Furthermore, staff believes that the problems occurred at Owens-Brockway and Ball-Foster 

Glass Container between 1994-1997would not occur with the two WGSs proposed by ETS Inc. 

because ETS proposed to place the two WGSs downstream of the ESPs. The ESPs located 

upstream of the wet scrubbers will collect particulate matter and prevent excessive particulate 

buildup in the wet scrubbers. In addition, ETS proposed to remove the two dry scrubbers located 

upstream of the ESPs. Trona injection in the dry scrubbers would no longer be needed, and thus 

Trona leakage to the ESPs would drop to zero, and the particulate loading to the ESPs would be 

reduced significantly.

To put the problems occurred at Owens-Brockway and Ball-Foster Glass Container into 

perspective, staff provides the following explanations: 

Owens-Brockway

Previously, Owens-Brockway operated three furnaces (Furnace A, B and C). In 1994, OwensBrockway installed a United McGill semi-dry/wet scrubber using soda ash as the scrubbing 

agent to control SOx. The particulate matter emissions from the three furnaces are controlled by 

three ESPs located downstream of the semi-dry scrubber (any two ESPs are in operation at one 

time, while one ESP is standby.) One of the furnaces (Furnace A, non-oxy fuel furnace) was 

shutdown in December 1996. During this period, the exhaust temperature dropped, resulting in 

condensation buildup and corrosion within the ESPs. Because of this reason, Owens-Brockway 

had to seek several variances from the SCAQMD Hearing Board in 1997 and finally decided to 

remove the semi-dry scrubber and replaced the semi-dry scrubber with the two dry scrubbers

using Trona, a very fine powder, as absorbent.

Staff believes that the problems with the semi-dry/wet scrubber and ESPs were not caused by 

equipment capability but equipment operation. Condensation problems would not have occurred 

in the ESPs if Furnace A were not shut down and the temperature of the flue gas entering the 

ESPs was high enough to prevent moisture condensation in the ESPs. The following, excerpted 

from Owens-Brockway Glass Container Corp.’s May 14, 1997 Petition for an Ex Parte, 

Emergency, and a Short Variance (Case No. 4472-9) supports this belief: 

“Prior to discontinuing the operation of Furnace A, the temperature of the combined 

exhausts from Furnaces A and C, when mixed with Furnace B exhaust, was high enough 

to keep the exhaust moisture content as vapor in the ESP. Since Petitioner has only been 

operating Furnaces B and C, the volume of exhaust has been reduced and the combined 

exhaust temperature has not been high enough to keep exhaust mixture in the form of 

vapor as exhaust enters the ESPs. Consequently, moisture condenses in the ESPs.” 

Staff believes that the problem with the semi-dry/wet scrubber and ESPs would not occur with 

the ETS’s proposal where the wet scrubbers would now be located downstream of the ESPs. 

The temperature of the exhaust gas stream from the furnaces would remain high enough to 

prevent condensation in the hot ESPs. 
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Proposed Amended Regulation XX Part I - 169 November 2, 2010 

Ball-Foster Glass Container

The problem occurred at Ball-Foster Glass Container (aka Saint-Gobain Containers) was very 

different in nature than the problem occurred at Owens-Brockway. Ball-Foster Glass Container 

did not use ESPs to control particulate matter. They operated a wet venturi, variable throat 

scrubber using soda ash as absorbent to control both SOx and particulate matter. In 1993, they 

converted their existing glass furnace to an oxy-fuel furnace which was operated with 

significantly less combustion air, which subsequently resulted in reducing the volume of exhaust 

flue gas from the furnace to the venturi scrubber and increasing the particulate loading to the 

scrubber. Staff believes that the excessive solids build-up in the scrubber system was due to 

failure to redesign the venturi wet scrubber to handle the excessive particulate loading after the 

conversion to the oxy-fuel furnace. In 1999, Ball-Foster Glass Container removed the venturi 

wet scrubber and replaced with a dry scrubber to control SOx and an ESP to control particulate 

matter.

Staff believes that the problem with excessive particulate buildup in the Ball-Foster Glass 

Container’s scrubber would not occur with ETS’s proposal since ETS proposed to place the wet 

scrubbers downstream of the ESPs. The ESPs reduces particulate matter emissions substantially 

and thus prevents particulate entrainment to the packed bed scrubbers.

It should be pointed out that Owens-Brockway and ALG had incorrectly assumed the 

configuration of ETS’s proposal. ETS proposed the removal of the two dry scrubbers upstream 

of the ESPs and replace those with two WGSs located downstream of the ESPs. 

Response #3

First, to put this matter into perspective, it should be noted that two sets of consultants, ETS and 

NEC, visited the Owens-Brockway facility, collected data, interviewed facility representatives 

and then independently ascertained that WGSs are technically and economically feasible for this 

facility’s furnaces. Both ETS and NEC have direct experiences in DGS, WGS technology as 

well as ESPs as applied to furnace operations at Owens-Brockway facility. Because of these 

reasons, staff has forwarded Owens-Brockway’s comment letters and staff responses to the

consultants for their input, and their input are incorporated in this response.79 

Second, the timing issue should also be mentioned. It has been almost two years since the 

consultant’s (ETS) analysis of the Owens-Brockway facility was finalized in December 2008. 

During this time, representatives from Owens-Brockway rarely participated in the SOx 

RECLAIM Working Group meetings or provided staff with any questions or feedback on the 

 

79 SCAQMD staff sent Owens-Brockway comment letter and staff’s responses to the consultants for 

review, and received confirmation back that they were in agreement with staff’s assessment. The 

consultants’ feedback is included in this response. E-mails from James Norton of NEC to Minh Pham on 

October 12, 2010, Marshall Bell of NEXIDEA to Minh Pham on October 12, 2010, and John McKenna 

of ETS to Minh Pham on October 27, 2010. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

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Proposed Amended Regulation XX Part I - 170 November 2, 2010 

consultant’s report. Staff recently received three comment letters from Owens-Brockway 

submitted on September 22, October 1 (addressed in Program Environmental Assessment), and 

October 21, 2010. The letters contain several incorrect assumptions and technical errors relative 

to ETS’s analysis as outlined below:

 

• (1st bullet) The commenter incorrectly assumes that the proposed BARCT configuration 

contains the dry scrubbers. In actuality, ETS proposed to remove the two dry scrubbers 

upstream of the ESPs and replace them with two new WGSs downstream of the ESPs.

• (2nd bullet) Owens-Brockway current setup shows that redundancy is needed for particulate 

control but not for SOx control. Owens-Brockway operates two dry scrubbers and has three 

ESPs connected by piping/valves, but only two are in operation at any one time and one 

remains in standby mode. ETS recommended the removal of the two dry scrubbers and the 

discontinue use of Trona, a very fine powder, in the two dry scrubbers will reduce the 

particulate loading and Trona entrainment to the ESPs. ETS recommendation may improve 

the reliability of the two on-line ESPs substantially and reduce the need to use the stand-by 

ESP. Owens-Brockway operates sufficiently with two dry scrubbers for SOx control without 

a need for redundancy. For these reasons, ETS recommended replacing the two existing dry 

scrubbers with two new WGSs to improve control efficiency but not necessarily redundancy. 

• (3rd bullet) Additional pressure drops were a concern for ALG since ALG incorrectly 

assumed that the BARCT control configuration recommended by ETS included both the two 

dry scrubbers and the two wet scrubbers. With ALG’s incorrect assumption, there would be 

additional pressure drops across the wet scrubbers that would need to be taken into 

consideration. However, ETS recommended the removal of two dry scrubbers upstream of 

the ESPs, and to replace those with two wet scrubbers downstream of the ESPs, and there 

would be no significant increase in pressure drop. In addition, if additional pressure were 

needed, it could be supplied with a fan. In ETS’s analysis, ETS had included the costs for a 

system fan in the vendor’s budgetary quote:

“Each system comes complete with all necessary pumps, reagent storage tanks, system 

fan, and stack.”

ETS made a determination based on their extensive knowledge and experiences with ESPs, 

wet gas scrubbers, and also dry gas scrubbers that the pressure drop would not be a concern 

in this situation. An additional fan or blower to push or pull the flue gas through the WGS 

would not make the control system recommended by ETS cost-ineffective since it has 

already been included in existing cost calculation. 

• (4th bullet) The three ESPs (two in operation and one stand-by) were designed to ensure that if 

one ESP experiences operational difficulties, the stand-by ESP will take its place. ETS 

recommended removing the dry scrubbers, and without Trona injection, the particulate 

loading to the two ESPs is expected to be reduced substantially and will improve the ESP 

reliability. ETS however did not recommend the removal of the stand-by ESP, but 

recommended Owens-Brockway to keep one stand-by ESP to handle upset conditions, and 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

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Proposed Amended Regulation XX Part I - 171 November 2, 2010 

thus maintain the integrity of the two wet scrubbers downstream of the ESPs. ETS did not 

view that building redundancy for SOx control by adding a third scrubber was necessary 

because monitoring the pH level and increasing the use of caustic may work as efficiently. 

• (5th bullet) As explained above, only two WGSs would be needed. Two consultants, ETS and 

NEC, both identified suitable, separate locations for placement of the WGSs, OwensBrockway is not expected to have site limitations associated with the placement of two WGSs 

within their facility.

• (6th bullet) The commenter failed to specifically identify what foreseeable additional costs 

that the consultants might not include in their analyses. ETS estimated a cost effectiveness of 

about $5,000 per ton SOx reduced and both ETS and NEC concurred that WGS technology is 

cost-effective.

• (7th bullet) Owens-Brockway reported that the facility is currently sending wastewater to the 

LACSD and the City of Vernon to be treated at a rate of 41.89 million gallons per year which 

equates to approximately 80 gallons per minute (gpm). Owens-Brockway has a maximum 

discharge limit of 131.4 million gallons per year (250 gpm). The increase in discharge due to 

the two wet gas scrubbers (WGSs) is 10 gpm which is expected to mainly contain soluble 

sodium sulfate that would result from using caustic solvent as the scrubbing agent. With an 

additional discharge of 10 gpm, Owens-Brockway is far below their permitted threshold of 

250 gpm. In addition, on October 26, 2010, following staff’s request, Owens-Brockway 

provided staff with their facility’s industrial wastewater discharge permit issued by the 

LACSD which shows that currently LACSD has effluent concentration limits for Arsenic, 

Cadmium, Chromium, Copper, Lead, Mercury, Nickel, Silver, Zinc, Cyanide, and total 

dissolved sulfides. There is no effluent discharge concentration limit for Selenium on 

Owens-Brockway’s industrial discharge permit. Furthermore, staff estimated the 

concentration of selenium that potentially could present in the waste water stream of OwensBrockway facility based on their annual emission reports from 2002-2009. Selenium 

concentrations in their waste water stream would be around 0.022 mg/L,80 much less than the 

threshold set in CFR, Part 268 – Land Disposal Restrictions for wastewater and non 

wastewater. For these reasons, staff believes that both the LACSD and the City of Vernon 

will be able to receive and treat an additional 10 gpm waste stream that contains trace of 

selenium and other inorganic compounds. The consultant (ETS) also allocated $225,000 into 

the scrubber equipment cost to handle the waste stream from the scrubbers (e.g. selenium). 

The amount of $225,000 was estimated based on information provided by Manufacturer D 

which has expert knowledge of WGS technology and WGS effluent waste treatment, and this 

amount was based on relevant experience with the waste stream from a glass manufacturing 

facility located in Seattle, Washington.81 In addition, ETS provided four options for OwensBrockway to treat the waste stream onsite in the Final Report: 

80 E-mail from Kevin Orellana to Minh Pham on October 26, 2010.

81 E-mail from ETS, Inc. to Minh Pham on October 27, 2010.
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Proposed Amended Regulation XX Part I - 172 November 2, 2010 

1) “The liquid blowdown from the scrubbers could be sent to a storage tank and 

recycled back to the furnaces for the batch wetting process.

2) The blowdown could be sent to a storage tank and then to an energy efficient 

dryer for liquid evaporation. The solid waste could then be placed in a 

hopper and recycled back to the furnaces.

3) The blowdown could be sent to a storage tank and then sprayed into the duct 

ahead of the precipitators to evaporate the water and collect the dry 

particulate in the ESP’s.

4) The blowdown could be sent to a storage tank and ran through a small skidmounted (app. 6’x 6’) filtration system prior to discharge to the local sanitary 

sewer system.” 

Further, since technology for selenium treatment is available, SCAQMD staff 

recommends that Owens-Brockway operators conduct their own evaluation of these 

recommended options to find an appropriate method to treat any selenium in the WGS 

wastewater. There are no significant environmental impacts expected with the options 

quoted above. While the commenter criticized Option 3 (the comments were based on 

the incorrect assumption about the continued use of dry scrubbers and Trona injection), 

no comments were submitted relative to Options 1, 2 and 4. 

• (8th bullet) One WGS for a FCCU has been installed and is currently operating at a refinery in 

the District. The exhaust gas stream from this existing WGS is expected to have similar 

characteristics (i.e. lower temperature, reduced plume buoyancy, caustic mist) as the proposed 

WGSs for Owens-Brockway. The WGS at the aforementioned refinery was evaluated to 

assure that it complies with all state and federal ambient air quality standards and a Permit to 

Operate was issued by the SCAQMD. If applications for the proposed WGSs are submitted 

by Owens-Brockway, the WGSs scrubbers will undergo an equivalent or similar evaluation. 

Moreover, there is no evidence of potential slip of caustic from WGS. 

Response #4

As a matter of maintaining perspective, it is important to note that Owens-Brockway currently 

holds 0.31 ton per day of RTCs and the remaining RTCs allocated to Owens-Brockway would be 

0.14 ton per day after the proposed 55 percent shave. Owens-Brockway’s SOx emissions in 

2005 were approximately 0.2 ton per day. Owens-Brockway indicated that the control efficiency 

of their dry scrubbers was demonstrated at 90 percent, but that they are operated at 75 percent to 

80 percent.82 If Owens-Brockway can operate their dry scrubbers at 90 percent, then the facility 

will be in compliance without any additional controls with the 55 percent shave since their 

emissions at 90 percent control would be 0.1 ton per day, 83 below the 0.14 ton per day allocation 

after the shave. Under this scenario, Owens-Brockway will have surplus credits of 0.04 ton per 

day, which can be made available in the open market and could generate a substantial revenue 

 

82 SCAQMD Engineering Evaluation, A/N 288744, March 1994. 

83 80% control of 1 ton per day = 0.2 ton per day, and 90% control of 1 ton per day = 0.1 ton per day 
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Proposed Amended Regulation XX Part I - 173 November 2, 2010 

stream to the company. This revenue stream can be even larger if Owens-Brockway elects to 

install higher efficiency WGSs.

However, if Owens-Brockway elects not to operate their dry scrubbers at 90 percent control, 

then the facility operators can purchase 0.06 ton per day (0.2 ton per day 2005 baseline – 0.14 

ton per day = 0.06 ton per day) to be in compliance with 55 percent shave. The RTCs can be 

purchased from investors or from other SOx RECLAIM facilities that have surplus RTCs. The 

surplus pool has approximately 1.73 tons per day of unused RTCs in 2005, and 2.55 tons per day 

of unused RTCs in 2008. For these reasons, SCAQMD staff did not assume that OwensBrockway would shut down their facility because of the proposed 55 percent shave for SOx 

RECLAIM.

Response #5

Staff disagrees with ALG’s recommendation, BARCT technology is improving over time. For 

example, dry scrubbers operating at 80% control efficiency were considered as BARCT in 1994. 

Today’s control technologies routinely demonstrate 95+% control efficiencies and can achieve 

control levels of 5 ppmv or better. Therefore, Owens-Brockway should not be included in the 

list of exempt facilities in Table 5 of the PAR 2002.

Response #6

Staff and the consultants84 disagree with ALG’s technical assessment in a number of areas: 

• ALG incorrectly assumed configuration of the proposed BARCT to contain the dry 

scrubbers. Monitoring pH and sufficient use of caustic solvent for SOx control and having 

ESPs upstream for particulate control would prevent excessive particulate loading and 

catastrophic failure to the WGSs located downstream of the ESPs. 

• Three WGSs are not required for redundancy as each can be sized to handle the entire flue 

gas flow from the ESPs, therefore plot space limitations should not be a problem. Both 

consultants visited the site, evaluated the situation, and concurred that space would not be a 

problem.

• Operational problems are site- and equipment-specific, particularly in cases where process 

changes are made upstream of existing systems (e.g. the problem at Ball-Foster was due to 

excessive particulate loadings to the venturi scrubber after they converted their furnace to 

oxy-fuel furnace. The venturi scrubber should be redesigned to handle a lower flow with 

higher particulate loading from the oxy-fuel furnace. As new equipment would be designed 

for a specific installation, the design would take into account all operating modes and 

 

84 SCAQMD staff sent Owens-Brockway comment letter and staff’s responses to the consultants for 

review, and received confirmation back that they were in agreement with staff’s assessment. The 

consultants’ feedback is included in this response. E-mails from James Norton of NEC to Minh Pham on 

October 12, 2010, and Marshall Bell of NEXIDEA to Minh Pham on October 12, 2010. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

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Proposed Amended Regulation XX Part I - 174 November 2, 2010 

upstream conditions. Therefore, staff finds the problems which occurred at a different 

facility, which reused control equipment without being redesigned, would not apply to the 

Owens-Brockway facility. In addition, Owens-Brockway has three ESPs located upstream 

of the scrubbers to control particulate matter and thus will help prevent excessive buildup of 

particulate in the WGSs.

• Most importantly, dry scrubbers operating at 80 percent control efficiency is not today’s 

BARCT. Current state-of-the-art systems can reliably achive 95% or more SOx reductions 

and achieve SOx emission levels of 5 ppmv or lower. Staff therefore recommends the 

BARCT level for glass melting furnaces at 5 ppmv.

Response #7

Regarding the commenter’s suggestion to clarify the language in subparagraph (f)(1)(Q) of Rule 

2002, staff believes that the language, as currently stated, makes it clear that any facility entering 

the RECLAIM program after the date of adoption and that operates the basic equipment in Table 

4 shall have its SOx allocations determined according to the BARCT level listed in Table 4 or 

the permitted emission limits, whichever is lower. Existing facilities that operate the basic 

equipment listed in Table 4 will have their allocations adjusted in accordance with Rule 2002, 

subparagraphs (f)(1)(I) and (f)(1)(J) at the Table 4 BARCT levels, effective 2012. 

Response #8

The background on Owens-Brockway’s furnaces and control equipment provided by ALG is 

consistent with the information documented by ETS (i.e. testing on the dry scrubber 

demonstrated up to 90% control efficiency, however the systems typically operate at a 75 percent 

to 80 percent control.) In addition, staff knows of no installation in which a facility relies upon 

using dry scrubbers, dry ESPs, followed by wet scrubbers to achieve the emission reductions 

recommended by the consultants. However, staff believes that the level of 5 ppmv SOx (95 

percent control efficiency or more) can be achieved in practice using WGSs, is cost-effective and 

is not expected to create the severe problems alleged by the commenter’s technical assessment. 

SCAQMD staff’s responses to the individual comments are summarized as follows:

• Regarding the control efficiency of the dry scrubbers, it is interesting to note that the 2005 

emissions from the Owens-Brockway’s glass furnaces were about 0.2 ton per day. OwensBrockway reported that their dry scrubbers were demonstrated to achieve 90 percent control 

efficiency, but that they were typically operated at a 75 percent to 85 percent control 

efficiency. If the dry scrubbers are operated at 90 percent control efficiency level, then 

Owens-Brockway would emit approximately 0.1 ton per day and as such, would be in 

compliance with the proposed 55 percent shave without additional control.

• (Response to point #4 of ALG’s assessment) The proposed BARCT level for glass melting 

furnaces has been achieved in practice. Specifically, the Puget Sound Clean Air Agency in 

Seattle, Washington provided SCAQMD staff with source test and CEMS data that 

demonstrates compliance with 5 ppmv SOx levels at 96 percent control efficiency via Tri-
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Proposed Amended Regulation XX Part I - 175 November 2, 2010 

Mer’s Cloud Chamber scrubber for a furnace with a permit limit of 1.6 pound of SOx per ton 

of glass pulledbut tested at 0.0062 pounds of SOx per ton of glass pulled.85,86 Staff received 

information directly from the vendors and also from ETS (e.g. guarantee letters) 

demonstrating that the Cloud Chamber scrubber as well as packed bed scrubber, venturi 

scrubber, or open throat type of scrubber can be used to achieve 5 ppmv SOx level when 

appropriately designed and operated. The Cloud Chamber scrubber is functionally identical 

to other types of WGS in controlling acid gas (SOx). In addition, the commenter’s 

assessment about the control configuration recommended by ETS is incorrect. The control 

configuration recommended by ETS (which was proposed by Manufacturer A) consists of 

three existing ESPs followed by two new wet scrubbers. Manufacturer A and ETS 

recommended the removal and replacement of the two existing dry scrubbers with two 

WGSs downstream of the three existing ESPs. 

• (Response to 1st bullet under Point #4 of ALG’s assessment) The commenter assumes that 

three WGSs would be needed to correspond with the three ESPs units. Even though the 

three ESPs are connected by piping/valves, only two are in operation at any one time and the 

one remains in standby mode. Thus, there is no need to install three WGSs when there are 

only two operational ESPs at any one time. In addition, removing the dry scrubbers 

upstream of the dry ESPs and stopping the use of Trona would reduce the excessive 

particulate loadings to the ESPs, and consequently would reduce the likelihood of future 

loadings to the WGSs downstream of the ESPs. For these reasons, ETS recommended 

replacing the two existing dry scrubbers with two new WGSs. Owens-Brockway may 

choose to build a larger system for redundancy (e.g. 90,000 acfm instead of 60,000 acfm), 

which will cost more but will not make the BARCT recommended by the consultants 

become cost-ineffective (i.e. larger than $50,000 per ton) since the cost-effectiveness for the 

60,000 cfm system was estimated to be only about $5,000 per ton, and the capital costs are 

proportional to the (90,000/60,000) exp 0.6 = 1.28 factor.

• (Response to 2nd bullet under Point #4 of ALG’s assessment) Additional pressure drops were 

a concern for ALG since ALG incorrectly assumed that the BARCT control configuration 

recommended by ETS included both the two dry scrubbers and the two wet scrubbers. 

However, ETS recommended the removal of two dry scrubbers upstream of the ESPs, and to 

replace those with two wet scrubbers downstream of the ESPs. There would be no pressure 

drop across the dry scrubbers. If indeed, additional pressure drop is needed, a fan and a 

blower can be used to provide the required energy. Manufacturer A did include the fan into 

their proposal, therefore the concern of pressure drop seems irrelevant. 

• (Response to 3rd bullet under Point #4 of ALG’s assessment) The commenter incorrectly 

assumes that Trona will still be needed. Since ETS recommended removing the dry 

scrubbers with Trona injection upstream, and placing the WGSs downstream of the 

 

85 Horizon Engineering, “Source Test Evaluation Report for Saint-Gobain, Seattle, Washington, Glass Melting 

 Furnace No. 5 with Cloud Chamber Scrubber,” September 18, 2009. 

86 CEMS Summary Report from Saint-Gobain to Puget Sound Clean Air Agency, for a period from October 1, 2009 

 to October 31, 2009. 
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Proposed Amended Regulation XX Part I - 176 November 2, 2010 

particulate loading to the ESPs. There will no longer be any need for Trona, and the 

proposed configuration is expected to reduce substantially the amount of particulate loading 

to the ESPs. 

• (Response to 4th bullet under Point #4 of ALG’s assessment) There are several types of 

WGSs: 1) quench, vertical packed bed scrubbers as recommended by Manufacturer A; 2) 

simple open-throat scrubbers as recommended by Manufacturer D; or, 3) fluidized rotating 

scrubber as offered by Manufacturer B. NEC recommended Manufacturer D’s open-throat 

type and ETS recommended Manufacturer A’s packed bed scrubber. Manufacturer A 

indicated that the packed bed scrubber can tolerate up to 20 mg/Nm3 of insoluble particulate 

without clogging; and if the particulate is soluble (e.g. sodium sulfate), then the packed bed 

scrubber would not have a problem with plugging. 87 Since ETS proposed to use caustic 

which would form soluble sodium sulfate, plugging problem is not likely to occur. The SOx 

RECLAIM program does not require Owens-Brockway to install any particular type of 

scrubber. In fact, Owens-Brockway is encouraged to further conduct study and research to 

determine the type of WGSs and solvent that best fit their operation and emission profiles.

• (Response to 5th and 6th bullet under Point #4 of ALG’s assessment) Please refer to Response 

#3 (7th bullet). Owens-Brockway reported that the facility is currently sending wastewater to 

the LACSD and the City of Vernon to be treated at a rate of 41.89 million gallons per year 

which equates to approximately 80 gallons per minute (gpm). Owens-Brockway has a 

maximum discharge limit of 131.4 million gallons per year (250 gpm). The increase in 

discharge due to the two wet gas scrubbers is 10 gpm which is expected to mainly contain 

soluble sodium sulfate that would result from using caustic solvent as the scrubbing agent. 

With an additional discharge of 10 gpm, Owens-Brockway is far below their permitted 

threshold of 250 gpm. For these reasons, SCAQMD staff believes that both the LACSD and 

the City of Vernon will be able to receive and treat an additional 10 gpm waste stream for 

selenium. However, in the event that the LASCD or City of Vernon would reject the 

additional 10 gpm in the waste stream, ETS provided four options for Owens-Brockway to 

treat the waste stream onsite and allocated $225,000 for this treatment in response to OwensBrockway’s comment received on December 2, 2008.88 Further, since technology for 

selenium treatment is available, SCAQMD staff recommends that Owens-Brockway 

operators conduct research to find the solution for their particular facility if the problem 

would occur if WGSs were installed. While the commenter criticized Option 3 (the 

comments were based on the incorrect assumption about the continued use of dry scrubbers 

and Trona injection), no comments were submitted relative to Options 1, 2 and 4 implying 

that the commenter did not disagree with the consultant. In addition, please refer to 

Response #2 for discussion related to the breakdown variances at Owens Brockway and Ball 

Foster El Monte facility.

 

87 Email from Manufacturer A to Minh Pham – Solution Based Absorbents for Scrubbers, January 29, 2010. 

88 ETS’s responses to Comment letter from Owens-Brockway. E-mail from Mark Tussing of OwensBrockway to Minh Pham on December 2, 2008 
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Proposed Amended Regulation XX Part I - 177 November 2, 2010 

• (Response to 7th, 8th and 9th bullet under Point #4 of ALG’s assessment) There are hundreds 

of scrubbers operating across the nation that currently utilize caustic solution (NaOH, 50 

percent by weight) as a scrubbing agent. The commenter has failed to provide evidence to 

support the claim that the use of caustic solution will create additional environmental 

impacts, other than what was already identified and analyzed in the Draft PEA. While 

caustic solution is a very common scrubbing agent, it is not the only solvent that can be used 

in Manufacturer A’s scrubber. Owens-Brockway may select other solvents such as soda ash, 

a common element at a glass plant, as an alternative scrubbing agent

• (Response to Point #5 of ALG’s assessment) Three WGSs are not required for redundancy 

as each can be sized to handle the entire flue gas flow from the ESPs in the existing facility. 

Both ETS and NEC were in agreement that three WGSs are not needed and space is not a 

problem. They identified two different separate locations at the site for the scrubbers. 

• (Response to Point #6 of ALG’s assessment) ETS analysis included all of necessary costs. 

NEC recommended raising ETS’s costs to include contingencies, costs for additional ducting 

and valves for an alternative location; and the commenter indicated that additional costs for 

CEMS upgrade were also needed. Including all of the additional costs suggested by NEC 

and the commenter would not make the BARCT recommended by ETS cost-ineffective. 

NEC concurred that the control costs for WGSs would be cost-effective for glass melting 

furnaces.

• (Response to Point #7 of ALG’s assessment) Refer to Response #2. The commenter refers 

to a site-specific problem (clogging problem) that occurred at Ball Foster, El Monte facility 

which is not applicable to their particular facility.

• (Response to Point #8 of ALG’s assessment) Refer to Response #2.
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Proposed Amended Regulation XX Part I - 178 November 2, 2010 

Responses to WSPA’s Comments Received from March 2010 to

August 2010 

Stranded Investments of Rule 1105.1 

Comment #1

Actual cost information from refineries has been submitted to the District. We understand that 

Staff has initially reviewed the information and still feel that the documented costs seem “high” 

compared to District expectations. 

The District Staff’s position is a concern to WSPA and our members, because the affected 

refineries documented actual costs incurred to comply with previous SCAQMD rules. WSPA 

members have been open and factual in providing this documentation. 

The result is entirely consistent with WSPA’s previous Rule 1105.1 cost-survey that showed 

implementation costs were 3-5 times (or more) greater than the preliminary cost estimates made 

by District Staff and District consultants. We believe the documented actual installation costs 

are superior to any pre-rule cost estimates. 

The District should accept the cost data provided by the refineries and acknowledge the fact that 

the actual costs are higher than the District’s pre-implementation estimates. As we move 

forward, the District should consider these actual costs in establishing future cost estimates for 

control technology. 

Response #1 

The cost information submitted by the refineries to comply with Rule 1105.1 has varied 

considerably in content and level of detail. On this basis, it has been very difficult for staff to 

ascertain costs that were directly attributable to the Rule 1105.1 and the costs that were the result 

of corporate decisions or those that extend to other facility operations (e.g., augmentation of 

substations). 

However, there was a reasonable agreement relative to the equipment cost estimates and actual 

equipment cost incurred but large divergence relative to the actual installation costs asserted by 

the refinery and original estimates by the AQMD consultant and even WSPA’s consultant. The 

industry’s delay in implementation (due to the litigation initiated by WSPA) had a direct impact 

on the increased costs on construction materials and labor. As reported by the refineries, all 

refineries selected to use the same ESP’s manufacturer (Hamon Research Cottrell) and same 

contractors (Jacobs Engineering/ Hamon Research Cottrell) during a short 

construction/installation period from the mid of 2007 – mid of 2008. This compressed 

construction schedule had a strong negative impact on the union labor costs and the management 

costs, and thus inflated the implementation costs of the projects. In addition, all refineries 

selected to build extra redundancy to their ESPs, and upgrade other systems (e.g. substation, 

NOx and SOx monitoring) that may not be directly related to the FCCUs. Furthermore, the 

market experienced a surge in steel prices in 2008. These facts together explain the differences 

in the costs estimated pre- and post- rule development by staff and AQMD consultants as well as 
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Proposed Amended Regulation XX Part I - 179 November 2, 2010 

those that were provided by industry. Please also note that all of the cost figures submitted 

significantly varies with the costs incurred by Chevron for their ESP installation in the early 

nineties, even when adjusted to current dollars. Detailed analysis is shown in Appendix E. 

It is very important to note that in several meetings with the District, WSPA members indicated 

that if they installed wet gas scrubbers, they need to remove the ESPs and thus the installation 

costs for the ESPs would be stranded. None of the consultants supported the perspective that 

there is a stranded investment issue. In other words, based on the feedback received, the 

installation of the SOx control technology under consideration to meet the proposed BARCT 

levels will not necessitate removal of previously installed equipment to control PM. It is 

understandable that there would be certain costs associated with such equipment alterations as 

augmenting the exhaust flow to overcome increased pressure differentials. However, the 

potential problem of a stranded investment, according to the consultants, does not exist. 

Legal Mandates and SOx Shave Methodology

Comment #2

In a meeting with the District on March 5, 2010, one WSPA’s member cited H&S Code 

39616(b)(2) – “A market-based incentive program ..... may substitute for 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, and may be implemented in lieu of some or all of the 

control measures adopted by the district pursuant to Chapter 10 (commencing with section 

40910) of Part 3.” This person asked whether the District has legal authority to make BARCT 

more stringent for SOx, a primary pollutant that is already in attainment, solely because SOx is 

a precursor of PM2.5 and the Basin is not in attainment of PM2.5/PM10. 

Response #2 

The cited provision does not limit the market incentive program to pollutants listed under 

Chapter 10. Indeed, Section 39616(b)(1) provides that the District Board may adopt a market 

incentive program as an element of the district’s plan for attainment of the state or federal 

ambient air quality standards. Thus, the District has legal authority that goes beyond controlling 

primary pollutants stated in Chapter 10. Chapter 10 covers pollutants such as NOx, SOx, and 

CO. In this case, the District is in non-attainment for PM2.5 and PM2.5 is a pollutant that is not 

covered under Chapter 10. One of the reason staff is amending Regulation XX is to reduce SOx 

in order to help the Basin attain the PM2.5 standards in 2015 and 2020. 

It should be noted that SOx is a significant building block of PM2.5. Chemical speciation of 

PM2.5 samples indicated that in the South Coast Air Basin 25% of the ambient PM2.5 is 

attributed to contribution from sulfates. Furthermore, SOx reductions are highly effective in 

reducing ambient PM2.5 levels as compared to other primary and secondary contributors to 

PM2.5 formation (1 ton SOx = 1.5 tons PM2.5 = 15 tons NOx). Therefore, considering the level 

of NOx reduction needed to meet future ambient standards of PM2.5 and ozone and the fact that 

much of the needed NOx reductions are in the “black box”, the reductions of SOx are essential 

for the basin to meet the federal annual standard of PM2.5 by 2015 and the federal 24-hour 

average standard of PM2.5 by 2020. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 180 November 2, 2010 

As indicated in the 2007 AQMP, the control strategies included in the Plan to meet the annual 

PM2.5 standard when fully implemented will fall short meeting the 24-hour standard by 

approximately 30%. Therefore, additional reductions above and beyond the control strategies 

committed in the 2007 AQMP for meeting the 2015 annual PM2.5 standard are necessary to 

meet the 24-hour PM2.5 standard in 2020. For further information, please refer to Chapter 5 of 

the 2007 AQMP. It should be noted that EPA is in the process of revising the PM2.5 standard. 

Comment #3 

In a meeting with the District on March 5, 2010, one WSPA’s member cited H&S Code 

39616(c)(1) “The program will result in an equivalent or greater reduction in emissions 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”. This person indicated that RECLAIM universe changed substantially from 1993 

from 42 facilities to 32 facilities today with a very different emission profile. Why can’t the 

district use the most current emissions distribution (e.g. 2005-2009) to estimate future RTC 

reductions and demonstrate attainment (or equivalency)? Why is there a need to base the 

estimation of RTC reductions on 94 or 97 baseline and emission profile? Does the H&S Code 

(or Regulation XX) restrict the district to use current emission profile? 

Response #3

For a market based incentive program, staff is required by the H&S codes to conduct periodic 

BARCT reassessment and demonstrate equivalency with command-and-control rules which 

would otherwise be developed as a result of BARCT reassessment: 

“...achieve an equivalent or greater level of emission reductions at an equivalent or 

lower cost as would have been achieved under a command-and-control rule” 

The H&S codes do not restrict staff in using the current emission profile in 2005 to estimate 

RTC shave specify a specific compliance year that staff must use to estimate the RTC 

reductions. The H&S code requires staff to apply BARCT when it is available and costeffective, and demonstrate equivalency with command-and-control rules. Staff selected to use 

the 1997 baseline to be consistent with the NOx RECLAIM approach which was also 

recommended by WSPA’s members in 2008-2009. The 1997 baseline reflects the emission 

profile at the time frame where no significant SOx control effort were undertaken by the 

RECLAIM facilities and therefore reflects equitable capture for future control efforts than the 

2005 baseline. Please refer to Section 13.3. 

Comment #4

District Staff has proposed a SOx RECLAIM shave methodology that was designed to be 

consistent with the method used for the NOx RECLAIM shave. WSPA feels, however, that the 

District’s proposed methodology inappropriately overstates the required reduction (i.e., % 

shave) in the RTC allocations, thereby making the shave extremely cost-ineffective. This holds 

true for both the BARCT adjustment as well as the market-adjustment that was recently 

proposed. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 181 November 2, 2010 

WSPA only recently (June 18) received the RTC allocation data that we requested at our 

meetings with Staff on March 5 and again on April 7. While the allocation data report 

forwarded to us by District Staff does not provide the level of detail we requested, we have begun 

a detailed review of the information. Having this information is a key to understanding how a 

reduction in RTC allocations can affect compliance costs and, indeed, the RTC market. 

Response #4 

WSPA is correct that the SOx shave methodology proposed by staff is consistent with the 

methodology used for the NOx RECLAIM shave. The idea of keeping the shave methodologies 

consistent was a theme that was repeatedly requested by WSPA and its members during our 

extensive dialogue over the last several months as well as through several comment letters. Staff 

believes that the proposed methodology for SOx RECLAIM, as in the case of NOx RECLAIM, 

reduced RTC allocations fairly and equitably, remaining true to the design principles of 

RECLAIM. 

As mutually agreed upon in the Work Plan, staff was open to alternative proposals, and as such, 

when asked by WSPA, staff provided WSPA with initial allocation data that was highly resource 

intensive to produce. At the March 5, 2010 meeting WSPA and its members did not request the 

RTC allocations. At the April 7, 2010 meeting such a request was made with very little input on 

the level of detail. In response, staff explained that the information requested would be a very 

resource intensive undertaking and would take several weeks to assemble. To that end staff 

spent a considerable amount of time assembling the allocation tables and meeting with each of 

the refineries, explaining their particular allocation profile line-by-line or equipment-byequipment specification. The level of detail and the form of the information presented was, in 

part, staff’s effort to be sensitive to WSPA’s concerns regarding confidentiality and anti-trust 

issues. 

Comment #5 

WSPA proposed methodology (WSPA’s presentation in the Refinery Committee Meeting on 

August 18, 2010) is summarized as follows: 1) use the 2005 actual emissions as baseline, 2) no 

new BARCT for boilers/heaters, SRU/TGs and cement kilns, 3) no shave for 1.98 tons per day 

unused RTCs converted from ERCs and Clean Fuel adjustments, 4) consider 10% - 20% 

compliance margin consistent with the operating requirements at some facilities and past 

practice. WSPA’s proposal results in 3.86 tpd shave. WSPA proposes 3 tpd shave by December 

2014 and the remaining no sooner than December 2019. WSPA also proposes across-the-board 

shave. 

Response #5 

Please see Responses to Comment #3 and #4. Using the 2005 baseline will result in 59% shave, 

not 55% shave as using 1997 baseline. BARCT for heaters/boilers will remain as Tier 1, and 

staff did not claim any reductions from 2005 from boilers/heaters category. Staff believes that a 

new BARCT can be set for SRU/TGs and cement kilns at 5 ppmv because retrofit control 

technologies are available. A 10% compliance margin is used to be consistent with NOx 

RECLAIM. The 1.98 tons per day RTCs converted from ERCs should be shaved in a similar 

fashion than other RTCs. Currently, in RECLAIM program, the 1.98 tons per day was shaved at 

a rate of 35% from Tier 1 to Tier 2. In comparison, ERCs of non-RECLAIM facilities do not 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 182 November 2, 2010 

inherently hold their values to eternity, non-RECLAIM ERCs are often recalled and reduced per 

Regulation XIII. It should be noted that unused RTCs are abundant in the market (in 2005, the 

unused RTCs were 11.77 – 10.04 = 1.73 tpd, and in 2008, the unused RTCs were 11.77 – 9.22 = 

2.55 tpd.) As such, WSPA’s proposal of 3.86 tpd for future RTC shave comes short, will not 

result in the necessary actual emission reductions in order to provide protection to the 17 million 

people in the Basin against the harmful effects of PM2.5. 

BARCT Determination 

Comment #6 

The Norton Engineering Report (released by the District on June 17 2010) has called into 

question the cost analyses previously performed by the District and its consultants. It appears 

that the ultimate conclusion of Norton Engineering is that the District’s RECLAIM costeffectiveness analysis should be revised. 

Response #6 

It is true that the Norton Engineering Report identified some areas of disagreement related to the 

cost estimates and recommendations provided by the previous consultants. However, these were 

limited in scope, primarily reflecting the differential cost of reassessing control equipment and 

their placement on the refinery property. Staff provides a thorough comparison of the 

approaches by the two sets of consultants in this revised draft staff report. 

Comment #7 

While NEC only relied upon the analysis and data provided by the initial consultants, NEC 

found numerous instances where the District’s initial consultants erred by identifying unproven 

or untested technology and underestimating construction, labor or materials costs. 

Response #7 

We need to be clear on the term “unproven or untested” technology. In some instances, NEC 

indicated that the control technologies have not yet been proven or tested in the petroleum 

refinery and cement industry areas. However, these are not “unproven or untested” in the sense 

of not being commercially available or in use in other applications. These types of controls 

would be better characterized as transferrable technologies. NEC incorporated increased costs in 

order to compensate for uncertainty relative to technology transfers. 

Staff did not agree with WSPA that NEC found the initial consultants severely underestimated 

construction, labor and materials costs. NEC has used a different approach than the initial 

consultants to estimate the project costs. For example, for FCCU’s wet gas scrubbers, NEC 

indicated that: “The NEC workup for the TIC89 for four of the five plants agreed reasonably well 

with that of the original estimates, being within +8%/ -3%. The NEC estimate for Refinery #3 

was 25% higher due to the necessity to design for particulate collection.....” Staff has estimated 

the project costs based on NEC’s input as shown in Chapter 12. The project costs based on the 

 

89 TIC = Total Installed Costs 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 183 November 2, 2010 

initial consultants’ input are $630 millions, and the project costs based on NEC’s input are $738 

millions, within 20% of the initial consultants’ estimates. 

 

Comment #8 

Norton Engineering Report cites examples that would raise compliance costs in all source 

categories, which in turn would raise the District Staff’s cost estimate for the District’s proposed 

shave significantly above the current level of $745 million. 

Response #8 

When one considers the capital investment to comply with staff’s proposal there is about a 21 

percent cost differential between Norton Engineering and the previous consultants. Such 

differential are within the margin of error for the analysis conducted and cannot be viewed as 

significant and in fact reflect different approaches along with newly acquired data. In contrast, 

staff has difficulties in justifying the cost figures from WSPA which are 200 to 300 percent 

higher than the estimates presented by the consultants. 

Comment #9 

The Norton Engineering Report sheds new light on the issue of what technology is technically 

feasible, achieved in practice and cost-effective; therefore, it directly affects BARCT 

determination and should cause the District to rethink its proposed reductions in the RTC 

market. 

Response #9 

As mentioned above, the cost differential between the two sets of consultants is within the 

margin of error of the analysis conducted and in staff’s view does not materially affect staff’s 

earlier BARCT determination. Please also see response #7. 

Comment #10 

As a follow-up to the release of the Norton Engineering Report, we request that the District make 

the Norton Engineering staff available to meet with WSPA members individually so they can 

understand the details associated with the Norton Engineering Report. 

Response #10 

In the spirit of being sensitive to WSPA’s confidentiality and anti-trust concerns, facilities and 

vendors in the final report by Norton Engineering are de-identified. Staff would be happy to 

meet with each of your members to let them know about their facility-specific information 

meeting with representatives of Norton Engineering may not be necessary after all. 

Comment #11 

WSPA requests the District to re-estimate the cost effectiveness based on Norton Engineering’s 

estimates and make the report available to WSPA’s members for comments. WSPA estimated the 

total costs to comply are about $2.7 billion as shown in WSPA’s presentation at the Refinery 

Committee Meeting on August 18, 2010. On April 7, 2010, WSPA also provides staff cost 

estimates based on ENVIRON’s report (WSPA hired ENVIRON to collect data and perform 

analysis with the results aggregated and de-identified). The aggregated cost estimates provided 

by WSPA on April 7, 2010 include: 1) Total compliance costs are about $2.85 billion for a 60% 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 184 November 2, 2010 

shave, and $550 million for 25% shave; 2) Distribution of the total costs for 60% shave: $1.45 

billion for FCCUs’ controls, $436 million for SRU/TGs’ controls, and $960 million for other 

improvements; and 3) Distribution of the total costs for 25% shave: $84 million for FCCUs’ 

controls, $342 million for SRU/TGs’ controls, and $127 million for other improvements. WSPA 

estimates $60,811.68 per ton for 60% shave scenario and $28,165 per ton for 25% shave 

scenario for refineries as of April 7, 2010. 

Response #11 

Staff is very sensitive about the costs estimated by WSPA, and plan to work in concert with 

WSPA to understand WSPA’s estimate of almost 3 billion dollars for the proposed project. It 

seems that WSPA may include other costs above and beyond the scope of SOx RECLAIM. 

While the refineries can modernize and upgrade their facilities to respond to market demand and 

other regulatory requirements, it is not justifiable to attribute all of these project costs to SOx 

RECLAIM project. 

Market Viability

Comment #12

District staff has committed to considering the use of compliance margin and non-tradable RTC 

accounts as tools to alleviate shortage of tradable RTC and ultimate failure of the SOx RTC 

market. WSPA is not aware of any progress to date. 

Response #12

Staff has used 10% compliance margin in the Draft Staff Report released on January 8, 2009. 

Staff is proposing additional safety valves to retain market viability, for example the proposed 

rule language for Rule 2002 (PAR 2002(f)(1)(O)) establishes non-tradable RTC accounts starting 

in 2015 to be made available in the event the market price of “discrete” RTCs is higher than $50 

K per ton. More specifically, in the event that the SOx RTC prices for “discrete” RTCs exceed 

$50,000 per ton based on the 12-month rolling average, staff will report to the Governing Board 

at a public hearing to be held no more than 60 days from staff’s determination, which will be 

posted on District’s web site. At the public hearing, the Governing Board will decide whether or 

not to convert any portion of the non-tradable/non-usable RTCs to tradable/usable RTCs. The 

portion of non-tradable/non-usable RTCs available for conversion will not include any portion of 

non-tradable/non-usable RTCs that are designated for previous compliance years and has not 

already been converted by the Governing Board, or any portion that has been included in the 

State Implementation Plan. 

Water Demand & Wastewater Discharge

Comment #13

District Staff indicated they will invite representatives from water regulatory agencies, 

purveyors and wastewater treatment facilities “to the next Refinery Committee meeting.” These 

representatives will be given the opportunity to provide their insights on the impact the Staff 

proposal will have on water supply and wastewater treatment. District Staff will also explore 

the extent to which the water demand can be offset by groundwater from wells owned and 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 185 November 2, 2010 

operated by refineries, by recycled water, or by other means. Associated costs will also be 

examined. 

Response #13

Representatives from water regulatory agencies, purveyors and wastewater treatment facilities 

were invited and attended the Refinery Committee Meeting on August 18, 2010. 

Representatives of the water purveyors attended the meeting confirmed that recycled water 

would be made available for the refineries in a near future. In addition, CEQA staff has sent the 

Draft Program CEQA document to the representatives of state water regulatory agencies, 

purveyors and wastewater treatment facilities for their comments on this issue. District Staff 

believes that the water demand can be offset by groundwater from wells owned and operated by 

refineries, by recycled water, or by other means. Furthermore, the consultants did include the 

associated costs of water (e.g. they used the costs provided to them by the refineries, $900 per 

acre-foot recycled water) in their cost effectiveness analysis. 

CEQA Implications and Permitting

Comment #14 

Specifically with respect to permitting and CEQA compliance, WSPA members have not yet been 

contacted by District Staff for information related to construction, project emissions or any other 

environmental impacts. We encourage the District to address the program’s effects as 

specifically and comprehensively as possible, so that subsequent activities at RECLAIM facilities 

are addressed within the scope of the EIR. 

Response #14 

Staff has been in direct contact with WSPA members over the last several months for 

information related to construction, project emissions or any other environmental impacts. 

Based on this information, as well as information from other sources, staff did and will continue 

to do their best to address the program’s effects as specifically and comprehensively as possible, 

so that subsequent activities at RECLAIM facilities are addressed within the scope of the EIR. 

Comment #15 

WSPA appreciates the District’s willingness to prepare a comprehensive CEQA programmatic 

DEIR document to help streamline the permitting process for individual projects carried out in 

response to the requirements of PAR XX. However, WSPA feels that several projects to reduce 

SOx emissions will require modification to existing Title V/RECLAIM permitted equipment, may 

involve changing the existing process units by adding process vessels, enlarging existing process 

vessels and replacing one type of chemical solution with another type. These activities will be 

subject to various District regulations, particularly Regulation XIII – New Source Review, Rule 

1401 – New Source Review of Toxic Air Contaminants, and PSD for criteria pollutants and 

perhaps green house gas (GHG) emissions, as well as public review. Other projects may need 

offset exemption and in the absence of a SIP-approved Rule 1315, we suggest that the SCAQMD 

begin implementation of this element of the Work Plan as soon as possible. The first tasks would 

be to review issues such as the availability of offset credits, qualification for Rule 1304 offset 

exemption, new or larger releases to the flares, NSR and Subpart Ja applicability to flare 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 186 November 2, 2010 

modifications, Best Available Control Technology (BACT), Toxics – BACT, and analysis of 

potential risk increase under Rule 1401. 

Response #15 

Staff acknowledges WSPA’s comments and will plan to work with Engineering & Compliance 

to address these elements related to permitting as soon as possible. 

Comment #16 

WSPA met with staff on April 7 and 15, 2010. WSPA hired Environ to collect data from the 

refineries and perform analysis with the results aggregated and de-identified. The total costs 

and cost effectiveness provided by WSPA for 25% shave and 60% shave scenarios are 

summarized below. 

Total Costs ($Million) for 

SOx RECLAIM Project Summarized by WSPA/ENVIRON 

Response #16 

WSPA did not provide specific information that could be used for meaningful analysis. In 

addition,WSPA’s cost estimates were very different than the costs that staff received from the 

refineries directly. Furthermore, WSPA’s estimates did not reflect the 55% shave scenario that 

staff currently proposed. Staff identified three scenarios in WSPA’s estimates that were 

substantially different from the consultants’ estimates. Staff believes that these three estimates 

were exaggerated. The table below shows how staff could explain the gap between WSPA’s 

estimates and the cost estimates based on NEC/ETS/AEC and NEXIDEA’s recommendations. 

Estimates Explanation 

$2,850 million WSPA’s estimate for 60% shave 

-$700 million Remove costs for boilers/heaters control options 

-$101 million Remove costs for early controls already in place 

-$467 million Remove costs for cost-ineffective units 

$1,562 

-$700 million Remove overestimated costs for FCCU’s WGSs (2 outliers) 

+$196 million Add consultants’ estimated for FCCU’s WGSs 

-$459 million Remove overestimated costs for SRU/TG’s WGS (1 outlier) 

+$73 million Add consultants’ estimated for SRU/TG’s WGS 

Total $672 million This compares reasonably well with the consultants’ estimates of 

$630 - $750 million for the SOx RECLAIM project 

 For 25% Shave For 60% Shave 

FCCUs Contribution 83.57 million 1,454.51 million 

SRUs Contribution 341.79 million 436.10 million 

Others 127.11 million 960.20 million 

Total Costs 550.00 million 2,850.00 (2.85 billion) 

Cost Effectiveness $28, 165 per ton $60,812 per ton 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 187 November 2, 2010 

Responses to WSPA’s Comments Received on July 14, 2009 

• BARCT, Cost Effectiveness Analysis, and RTC Reduction Estimates 

Comment #1 

A methodology for making the BARCT determination and calculation of the SOx reduction 

should be developed by the District, and understood by the stakeholders, prior to conducting 

any analysis or any study. Staff must stay consistent with the 2005 NOx shave methodology. The 

identification of baseline year, starting emission factors, control factors, etc. has been lacking. 

Response #1 

The methodology for BARCT determination and RTC reduction estimates is transparent, has 

been provided to the stakeholders as early as in April 2008, and has been discussed at the June 

2009 Public Workshop, and many Working Group meetings since then. 

BARCT Determination 

SOx RECLAIM program is required by H&S Code 39616 code to: 

 “...achieve an equivalent or greater level of emission reductions at an equivalent or 

lower cost as would have been achieved under a command-and-control rule” 

To fulfill this requirement, staff has followed a traditional, transparent, BARCT determination 

methodology that is similar to the methodology used in any command-and-control rule 

development. The step-by-step BARCT determination process was summarized in the Draft 

Staff Report, Part III, released in June 2009. 

It should be noted that staff is not required to focus only on achieved-in-practice and fully 

commercialized available control technology (i.e. technology that either is being offered 

commercially by vendors, or is in commercial demonstration or licensing). Staff is obligated to 

find technology that can potentially reduce maximum amount of pollution and meet the 

requirement sated in H&S Code §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.” 

Thus technology that is both feasible and cost effective must be considered BARCT even they 

are not yet proven achieved-in-practice. A feasible technology is a technology that has been 

previously installed and operated successfully at a similar type of source, or has practical 

potential for application to the source, i.e. has been successfully applied to similar sources with 

similar gas stream characteristics. 

The potentially proposed BARCT levels for 7 categories of sources were first introduced to the 

public and the stakeholders in early April 2008, and have become the source of discussion in 

many Working Group meetings since then. Please refer to the Preliminary Draft Staff Report 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 188 November 2, 2010 

dated April 3, 2008 and subsequent Working Group meetings on April 3 and April 30, 2008 as 

well as in many separate task force meetings with WSPA and WSPA’s members since then. 

In late September 2008 to April 2009, the consultants carefully conducted another independent 

feasibility analyses for all of the potential BARCT identified by staff. They estimated the cost 

effectiveness factors for these technologies on a facility-by-facility basis. In their final reports, 

the consultants concluded that the proposed BARCT levels were feasible, available, and cost 

effective. 

Subsequent to the release of the consultant studies, their recommendations were carefully 

evaluated by staff and subject to another step of refinement. The objective of this refinement 

was to optimize the effectiveness of the subsequent staff proposal by removing certain control 

technology recommendation with the lowest favorable cost effectiveness that allowed optimizing 

the emission reductions to be obtained relative to the capital investment to be incurred. 

RTC Reductions Estimates & Shave Methodology 

Staff followed the commenter’s recommendation to stay consistent with the NOx shave 

methodology that was developed by the District’s staff and agreed upon by WSPA and WSPA’s 

members in 2005. Even though staff was in agreement in principal with the desire to stay 

consistent with the 2005 NOx shave methodology, designing a shave methodology that is 

workable for the SOx RECLAIM program, but remains fair and equitable is not a trivial and 

simple task. 

To use the 2005 NOx shave methodology, staff invested tremendous amount of time and efforts 

to recover the 1997-1998 emissions baseline and the starting emission factors in 1993. Using the 

1997-1998 emissions baseline and the 1993 starting emission factors, staff estimated the control 

factors and RTC reductions as shown in Part III of the Draft Staff Report presented in the June 9, 

2009 Public Workshop. The RTC reductions shown in the June 2009 Staff Report (i.e. 7.09 tpd 

– 7.68 tpd) were very similar to the emission reductions estimated by staff in April 2008 (i.e. 

6.73 tpd – 6.77 tpd.) 

Comment #2 

Part I of the Staff report contains premature technology recommendations by the District. The 

attempt to identify these candidate technologies in advance was in conflict with the concept of 

utilizing third party consultants to conduct a study to determine potential technology 

recommendations. Any proposed BARCT should be eliminated from Part I and reserved for 

discussion in Part III. 

Response #2 

Staff disagrees with the commenter’s recommendation. Utilizing the third party consultants to 

conduct additional independent studies on BARCT from September 2008 – April 2009 should 

not be viewed as relinquishing the authority or obligation by staff from conducting their own 

independent research on BARCT and release any relevant information to the stakeholders. Part 

I, II and III of the Staff Report reflect the progression in the thought and evaluation process 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 189 November 2, 2010 

leading to the most recent staff proposal during this rule making process. Specifically, Part III of 

the Staff Report has utilized the information presented in Part I of the Staff Report (i.e. feasible 

control technologies) and Part II (i.e. cost information) in conjunction with other information 

(e.g. starting emission factors, 1997-1998 emissions baseline, growth factor) to estimate the RTC 

reductions. This approach is consistent with the requirements in H&S Code §40406 and §39616. 

Staff is now retaining all the information in Part I, and combining Part III and Part IV into Part I 

as a complete report. Part II is reserved to serve as a summary of the consultants’ analyses. 

Comment #3 

In the 2005 NOx Shave, District staff established the following specific criteria used to evaluate 

BARCT. Staff should use these criteria in evaluating measures for this SOx shave rule: 

o Does another air pollution control district or agency have BARCT that we have not 

identified, or have a more stringent BARCT level than the SCAQMD? WSPA’s opinion: No 

o Is the proposed BARCT level achieved in practice as retrofits? WSPA’s opinion: No 

o Is technology available and feasible for retrofits? WSPA’s opinion: Feasibility must take into 

account environmental, economic and energy impacts, based on this NO 

o Do manufacturers offer guarantees for achieving proposed emission levels? WSPA’s 

opinion: Guarantee letters were all prospective - contractor has not issued, or presented 

evidence of, guarantees at the recommended levels and corresponding demonstrated 

equipment operation functioning under those guaranteed letters. 

o Is retrofit technology cost-effective? WSPA’s opinion: No 

o Based on the above criteria, could a command and control BARCT rule have been proposed 

in the absence of the RECLAIM program? WSPA’s opinion: No 

Response #3 

Staff has examined the criteria listed above; however, staff disagrees with most of the 

commenter’s responses to these criteria. Staff’s responses are as follows: 

• Does another air pollution control district or agency have BARCT that we have not 

identified, or have a more stringent BARCT level than the SCAQMD? Staff’s response: No. 

Because of the severity of air pollution its seventeen (17) million residents have to endure, 

SCAQMD usually sets the most stringent BARCT emission standards in the nation. The 

more stringent BARCT standards are needed for the Basin to achieve the annual average and 

24-hour PM2.5 and ozone federal and state air quality standards in 2015, and 2020, and post 

2020, respectively. 

• Is the proposed BARCT level achieved in practice as retrofits? Staff’s response: Yes. The 

proposed 5 ppmv BARCT limits are achieved-in-practice for FCCUs (Valero Delaware 

Refinery, ConocoPhillips Refinery) and SRU/TGTUs (Sinclair Refinery, Casper Refinery.) 

The proposed technologies (e.g. wet/dry gas scrubbers) are commercially available, feasible 

to achieve 5 ppmv in all 7 equipment applications identified by staff, and they are cost 

effective to implement. 

• Is technology available and feasible for retrofits? Staff’s response: Yes. Wet/dry gas 

scrubbers are commercially available, feasible and cost effective for retrofits. Emerachem 

oxidation and absorption catalyst technology is commercially available, has been used in 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 190 November 2, 2010 

power plant application, but has not been used in a refinery application and the consultants’ 

conclusion is that the technology is transferable to refinery application. 

• Do manufacturers offer guarantees for achieving proposed emission levels? Staff’s response: 

Manufacturers have provided guarantee letters to the consultants and these letters were 

distributed directly to the refineries, as well as the Governing Board members and the public 

in the Stationary Source Committee meeting June 2009. 

• Is retrofit technology cost-effective? Staff’s response: Yes. Please refer to the consultants’ 

analyses. 

• Based on the above criteria, could a command and control BARCT rule have been proposed 

in the absence of the RECLAIM program? Staff’s response: Yes. It should be noted that if a 

command and control BARCT rule would be proposed, they individually could have more 

stringent reduction requirements than the 55% RTC reduction proposed for SOx RECLAIM. 

Comment #4 

There is no evidence to support the assertion that RECLAIM sources have the highest possibility 

to achieve the 3 ton/day target reduction compared to other SOx sources in the basin. 

Substantial reductions in SOx emissions have been made from refinery flares but are not 

properly credited in the 2007 AQMP. 

Response #4 

Staff acknowledges that significant progress has been made in reducing SOx from refinery 

flares. However, significant additional reductions are needed above and beyond those 

committed in the 2007 AQMP to meet the federal and state 24-hour PM2.5 standard. A 

reduction of 3 tons per day is achievable for SOx RECLAIM facilities taken from the following 

categories: 

• 1.76 tons per day RTC surplus for RECLAIM sources (11.76 tpd available RTC – 10 tpd of 

2005 emissions = 1.76 tpd RTC surplus) 

• Refinery boilers/heaters can reduce approximately 0.89 tpd reduction to meet Tier I standard 

applicable since year 2000 

• FCCU category alone can reduce approximately 3 tpd reduction estimated from the 2005 

emissions baseline. 

Contrary to the commenter’s observation, the 2007 AQMP properly credited the emissions 

reduction from the refinery flares in estimating the remaining emissions in future years. 

Comment #5 

WSPA believes that the BARCT analysis should be conducted on a source category by source 

category basis per the H&S code requirement and past practice of NOx 2005 RECLAIM shave, 

not on a facility-by-facility basis as performed by the consultants. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 191 November 2, 2010 

Response #5 

BARCT analysis was done on a source-by-source basis. In addition to that, staff asked the 

consultants to conduct a facility-by-facility analysis. Conducting a detailed facility-and unitspecific analysis was very time consuming and not required by the H&S code. 

Mindful of the implementation costs of control, staff instructed the contractors to conduct 

facility-by-facility site specific analysis to ensure that the proposed technology can be 

implemented cost-effectively at each facility. The BARCT analysis (e.g. use a top-down 

approach in the selection for BARCT, use of discount cash flow (DCF) method in calculating the 

cost effectiveness factor) was clearly written in the contracts’ Statement-of-Work. 

There are at least two reasons that make the facility site specific analysis possible for SOx 

RECLAIM but not for NOx RECLAIM: 

• The universe of sources in SOx RECLAIM is much smaller than the universe of sources in 

NOx RECLAIM. The NOx RECLAIM universe contains hundreds of boilers, heaters, 

furnaces, and ovens, which makes unit-by-unit analysis impractical. 

• The main control technology for NOx in refineries is low NOx burners which can be 

installed without the analysis of available plot space. The main control technology for SOx 

sources is a wet gas scrubber for which a unit-specific analysis was needed to assess 

available plot space. 

Comment #6 

WSPA believes that a BARCT determination must consider only technologies that are truly 

"available" and have been proven successful for an adequate period of time in commercial-scale 

applications. Even the District's definition in Rule 1302(h) (1) of BACT (apparently intended to 

be more stringent that BARCT) includes the principle of a control technology having been 

"achieved in practice for such category or class of source" 

Response #6 

Because BACT is a permitting requirement, it must be achieved in practice to be available at 

time of permitting. BARCT however can be more stringent than BACT because additional time 

can be provided to allow technology to mature. 

Comment #7 

Proposed BARCT emission levels lack proper substantiation (e.g. six months of operation at a 

certain performance level). This was not done for any of the source categories examined for the 

refinery. In fact, it cannot be done for the SRU systems proposed as BARCT because none have 

been used in refineries, much less sulfur plants. 

Response #7 

A technology does not have to be achieved-in-practice with 6 months of operation at a certain 

performance level to be defined as BARCT. A technology can be defined as BARCT if it is 

technologically feasible and cost effective. Wet gas scrubbing technology however is proven 

achieved-in-practice, and commercially available for refinery FCCUs and SRU/TGTUs. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 192 November 2, 2010 

Comment #8 

The cost effectiveness analyses are undermined because they do not include all of the true 

associated costs, including additional equipment needed to provide additional heat and steam. 

These gaps have created a significant problem for evaluating potential emission reduction 

technology applications, their cost effectiveness, and also the logistical applicability to specific 

facilities. It is inappropriate for the District to make technology recommendations based on 

incomplete or incorrect data. 

Response #8 

The consultants have carefully conducted facility and unit specific cost analysis. A contingency 

factor has been added to cover miscellaneous costs. This procedure is common to all cost 

estimates. The commenter did not specifically indicate in what applications the additional heat 

and steam were needed for, so the comment cannot be addressed . 

Comment #9 

Analyses of plot space requirements were performed ‘at the last minute’ and were incomplete 

and did not include equipment required outside the scope of vendor supplied equipment. This 

example of incomplete analysis and considerations for a “total application solution significantly 

understates potential costs and cost effectiveness. 

Response #9 

The commenter has incorrectly characterized the contractors’ analysis related to plot space. Plot 

space analysis was one of the key elements described in the contracts. 

The contractors conducted their plot space analysis early on in the project, not at ‘the last 

minute’. As stated in Task #1 of the Statement-of-Work, the contractors were required to 

conduct field visits at each RECLAIM facility to: 

“assess both physical and operational factors that would impact the feasibility and the 

cost of additional emission control equipment.” 

The contractors did not limit their analysis just to the vendor supplied equipment (e.g. wet gas 

scrubbers) but extended their analysis to cover ‘the total application’ and they thoroughly 

discussed the plot space issues with the facilities. As stated in the contractors’ reports: 

“Infrastructure items were discussed extensively. These include available areas for a 

scrubber for the FCCU, room on existing pipe racks, piling, Electrical Substation......., 

control systems, steam, water, available sewer allocation.....” 

Comment #10 

The “average cost effectiveness” ratio presented in the staff report is not an appropriate 

representation of the cost effectiveness of available SOx reduction technologies and has the 

potential to mislead policy makers. A clear cost-effectiveness threshold should have been 

established upfront. An incremental cost effective analysis should have been completed to 

provide a clear relationship between incremental SOx reductions, cost and the associated 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 193 November 2, 2010 

emission reduction technology employed. At a minimum, incremental cost effective analysis at 

4tpd, 6tpd and 8tpd SOx reductions should be completed to satisfy the following requirements in 

the State H&S Code. 

Response #10 

Cost effectiveness factors are process and facility-specific. To present all possible information 

on cost effectiveness factors to the policy makers and the public, staff has provided four types of 

cost effectiveness factors in Step 3 of Section 17.2 of Chapter 17 of Part III of the Draft Staff 

Report: 

1. Individual cost effectiveness for a specific emitting source (e.g. cost effectiveness for each 

FCCU); 

2. Average cost effectiveness for the category of source (e.g. average cost effectiveness for five 

FCCUs in the Basin); 

3. Average cost effectiveness for the entire project; and 

4. Incremental cost-effectiveness for the entire project 

The cost effectiveness factors in this project ranged from $2K to $47K per ton. The individual 

cost effectiveness factors for each control at each facility (e.g. $14K per ton for Refinery 1’s 

FCCU wet gas scrubber), the average cost effectiveness factor across a class of equipment (e.g. 

$25K per ton for all FCCUs’ wet gas scrubbers); and the average cost effectiveness factor for the 

entire SOx RECLAIM project (e.g. $17K per ton) were shown in Appendix III-A of the Draft 

Staff Report. 

Staff did not select a clear threshold for cost effectiveness at the time the draft staff report was 

released. After further consideration, staff selected a cutoff threshold of $50K per ton as a 

means of removing the least cost-effective control technology recommended by the consultants 

and optimizing the effectiveness of the most recent staff proposal. 

At the time the draft staff report was released, staff estimated the incremental cost effectiveness 

between the consultant’s proposal (Scenario 2: 6.5 tpd) and staff’s proposal (Scenario 3: from 

6.1 tpd to 6.4 tpd) as shown in Section 18.1 of Chapter 18 of the Draft Staff Report. Even 

though the overall cost effectiveness of the consultants’ proposal was within a reasonable range, 

the incremental cost effectiveness compared to staff’s proposal was significantly large ($300 

million per incremental SOx reduced), and because of this reason, staff did not select the 

consultants’ proposals. 

Comment #11 

There is no evidence in this document that staff considered environmental, energy, economic 

impacts in any of the proposed scenarios. Until all of these analyses and considerations are 

completed, making a BARCT determination is premature and arguably invalid. 

Response #11 

Staff is in the process of conducting additional analysis for environmental, energy and economic 

impacts to support the proposed BARCT determination in the draft staff report released at the 

Public Workshop in June 2009. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 194 November 2, 2010 

Comment #12 

In all cases, the BARCT recommendations are based on technology forcing emission levels. It is 

unlikely that under command and control, all of these BARCT proposals would become rules - 

particularly for those source categories that have only a single facility. It would be more 

appropriate to have a mix of more and less aggressive levels equivalent to a programmatic 

BARCT to allow the RECLAIM program to be viable. 

Response #12 

Staff disagrees with the commenter. Wet gas scrubbing achieving 5 ppmv – 10 ppmv outlet 

concentrations is not a technology forcing technology. It is a mature, commercially available, 

and achieved-in-practice technology for many of the affected equipment categories (e.g. FCCUs, 

SRU/TGs, glass furnace, coke calciner). 

For SOx RECLAIM, staff estimated a programmatic RTC reduction of 60%-65%. If AQMD 

would pursue and “single out” a facility for command-and-control rule, the reduction could be in 

the neighborhood of 80% - 95% or higher based on the feasibility of wet gas scrubbing 

technology. 

Comment #13 

The reliance on guarantee letters provided by the manufacturers is faulty and should not be 

relied upon to validate or support the emission reduction sustainability. 

Response #13 

Guarantee letters provided by the manufacturers are only one piece of information that staff 

relied on to judge the feasibility of the control equipment. In addition to the guarantee letters, 

staff also relied on achieved-in-practice information, source tests data, CEMS data, and expert 

consultants’ analyses. Furthermore, the sustainability of the emission reductions relies heavily 

on how the facilities operate and maintain their control equipment. If staff develops commandand-control rules, good engineering practices (e.g. annual maintenance, annual testing) would 

normally be crafted in the rule requirements to assure continuous compliance with the BARCT 

levels and guarantee the achievability of emission reductions estimated. 

Comment #14 

There is no BARCT determination for de-SOx additive, therefore it is inappropriate to consider 

de-SOx additives as an alternative feasible and available control technology 

Response #14 

In late August 2008, staff developed a testing protocol for de-SOx catalysts with the participation 

of WSPA and the refineries. Only one of the refineries volunteered to participate in the shortterm source testing from September 2008 – November 2008. From this short-term testing, this 

refinery was able to achieve approximately 7 ppmv SOx at 0% O2 and at the same time also met 

the PM10 emission level in Rule 1105.1. 

Comment #15 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 195 November 2, 2010 

Several data requests have been made of the SCAQMD: 1) clarification of how certain emission 

factors (starting and new) for FCC’s, SRU’s and boilers were derived for individual facility 

process units, 2) facility specific data/calculations be sent directly to the six individual WSPA 

member facilities, 3) derivation of the emission factors referenced in Appendix III-A of the Staff 

Report SOX RECLAIM Part III, and 4) 1997/2002/2005 baseline. 

Response #15 

The following information was provided to WSPA and the refineries: 

• Clarification of how certain emission factors (starting and new) for FCC’s, SRU’s and 

boilers were derived for individual facility process units was explained and provided in the 

Working Group meetings on July 30, August 13, and August 27, 2009 

• Derivation of the emission factors referenced in Appendix III-A of the Staff Report SOX 

RECLAIM Part III was explained and provided in the Working Group meetings on July 30, 

August 13, and August 27, 2009 

• Facility specific data/calculations were e-mailed directly to the six individual WSPA member 

facilities on July 17, 2009 

• The 1997 and 2005 baselines were presented in the Staff Report released at the June 2009 

Public Workshop. Staff did not provide the 2002 baseline, because there was no 

demonstrated need for that baseline. 

• Water & Wastewater

Comment #16 

There is no information regarding the total water related impacts of the dozen potential scrubber 

installations. The report provides a broad impact: for fresh water – between 1 and 90 million 

gallons per year for each scrubber, and for waste water – between 1 and 40 million gallons per 

year for each scrubber. Thus, the total impact could be as high as one billion gallons per year of 

fresh water (90 million gallons and 12 installations), and an increased wastewater load to 

Publicly Owned Treatment Plants (POTWs) as high as 440 million gallons per year (40 million 

gallons and an assumed eleven systems that would discharge to a POTW). 

Response #16 

The above estimated water usage and wastewater generated provided by the commenter (1 

billion gallons per year water usage and 40 million gallons waste water generated) are 

incorrect.90

In July 2009, staff developed a Survey Questionnaire to gather information on the current usage 

of water, the current amount of wastewater and solid waste generated, and the existing practice 

(e.g. ground water capacity and current pumping rate, recycled water usage) at the 11 top 

emitting facilities. The facility’s responses to staff’s Survey Questionnaire are summarized in 

 

90 The reported water usage and waste water generated for the SRU//TGTUs’ scrubbers estimated by the consultants 

in their final reports were not the same as estimated in the draft staff report. Perhaps, there was a typo in the figures 

(e.g. misplacing the decimal point). Staff has revised these figures based on the numbers provided by the wet gas 

scrubbers’ manufacturers. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 196 November 2, 2010 

Table XX, Chapter XX of the Staff Report. Based on the facility’s responses, the impacts of the 

project on water and waste water are as follows: 

• The total current water usage for the 11 facilities is 18,842 million gallons per year. This 

project would require 364 million gallons water per year. This impact reflects an estimated 

2% increase in water demand from these facilities relative to their current water usage. 

• The total current wastewater discharged by the 11 facilities is 10,556 million gallons per 

year. This project would generate about 160 million gallons per year, or about 1.5% increase 

in wastewater generated from these facilities relative to their current wastewater discharge. 

Comment #17 

The consultants admitted that there are a number of disadvantages to wet gas scrubbing: 1) 

Fresh reagent and fresh water must be fed to the unit to replace the water lost as waste water 

and the reagent consumed in the reaction, 2) The reaction products are generally salts that must 

be carried away with a waste water stream, 3) Sodium sulfite and sodium bisulfite salts are 

created and these salts increase the chemical oxygen demand (COD) of the waste water, 4) A 

large visible plume usually forms as water is evaporated, which is an aesthetic concern and 

constitutes a loss of water for the refinery. 

Response #17 

Wet gas scrubbing technology is a mature technology. As any other control technology, wet gas 

scrubbing also has its own advantages as well as disadvantages. Regardless of the disadvantages 

cited, many facilities in the U.S. and in the District have chosen to install and successfully 

operate wet gas scrubbers to control SOx and particulate matter from various types of stationary 

sources. Clearly, those facilities believe the advantages of the technology outweigh any 

disadvantages. As written in the Module 3A report, the consultants objectively commented on 

both the advantages and disadvantages of wet gas scrubbers and cited the following advantages: 

“There are a number of advantages to wet gas scrubbing. Operation of the package is 

not particularly complex, and the process hazards that accompany it are typically 

manageable in a refining environment. In addition, such units are very effective at 

removing SOx from gas streams and can also reduce emissions of particulate matter into 

the air.” 

• Fluid Catalytic Cracking Units, SRU/TGTUs, Boilers/Heaters

Comment #18 

There are no records to support the performance of the wet gas scrubber on the FCCU at the 

Valero Delaware City Refinery. 

Response #18 

The Delaware Department of Natural Resources and Environmental Control (DNREC) provided 

staff with approximately 18-months 1-hour CEMS data (a total of 10,386 records). The average 

concentration of this 18-months period of operation was 1.2 ppmv at 0% O2, well below the 

proposed BARCT level of 5 pmv. In addition, there is a wet gas scrubber installed and operated 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 197 November 2, 2010 

at a refinery in the District since August 2008. The performance of this wet gas scrubber (i.e. 

mass emissions from CEMS for a period of 265 days and a performance source test result) was 

listed in Appendix III-D of the draft Staff Report. 

Comment #19 

It is inappropriate for the consultants to make a BARCT recommendation. 

Response #19 

Staff did not view the consultants’ action as inappropriate. As shown in the Statement of Work, 

the consultants were required to present various levels of feasibility and estimate the emission 

reductions and cost effectiveness at each level. They indicated in their report that wet gas 

scrubbing technology could achieve a level as low as 1 ppmv and they provided emission 

reductions and cost effectiveness associated with this level as required by the contract. 

However, they also concluded that a level of 5 ppmv is more realistic to implement. Therefore, 

they recommended that level be BARCT even though they were not required to do so by the 

contract. This is only a recommendation and should not be viewed as inappropriate. During the 

process of formulating its final BARCT proposal, staff will review, verify and use all technical 

information provided by the consultants as well as information from other sources. Staff is 

ultimately responsible to make a final BARCT recommendation to the Governing Board for its 

consideration, and the Governing Board will ultimately make a final decision on what are the 

appropriate BARCT levels. 

Comment #20 

In the report, the contractors stated that "... it is the recommendation of the ETS team that nonregenerative wet scrubbing be considered on a purely technical basis (emphasis added) as 

BARCT ...with an overall BARCT level of 5 ppmv." It is apparent, that the contractor made 

their unauthorized recommendation solely on a technical basis, and therefore it is not a 

defensible BARCT determination. 

Response #20 

The consultants’ recommendation was not purely based on technical information. The 

consultants conducted a detailed engineering evaluation and cost analysis assessment strictly 

adhered to the Statement of Work: 

“.....visit each of the six local refineries in the Basin to gather site specific information 

(e.g. operating conditions) and to conduct site-specific feasibility assessment 

analysis....evaluate the existing commercially viable control technologies, starting with 

the most effective control technology, and make recommendations to the District on 

various technologies that could potentially be used to achieve additional emission 

reductions, on various concentration targets that could be achieved with each 

technology, the estimated emission reductions, the multimedia pollutant impacts (e.g. 

water, waste), energy impacts of the technologies, and the associated cost effectiveness 

associated with the control technology.” 

On a purely technical basis, the consultants recommended a level as stringent as 1 ppmv. 

However, after carefully considering costs and other impacts, the consultants recommended a 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 198 November 2, 2010 

level of 5 ppmv for FCCUs with the use of wet gas scrubbing technology, 5 ppmv for 

SRU/TGTUs with wet gas scrubbing technology or oxidation catalysts, and 40 ppmv for 

boilers/heaters with various types of fuel gas treatment techniques. As mentioned in previous 

responses, in formulating its BARCT proposal, staff carefully evaluated the consultants’ 

recommendations and introduced several refinements to improve and optimize the effectiveness 

of staff proposal. 

Comment #21 

The contractors claimed that it was impossible to address every one of the individual cases and 

therefore the team made use of generic, but representative quotations and published cost studies. 

Because there are only five FCCUs in the Basin, and because the estimated present worth of 

implementing the proposal for FCCUs alone is $493 million, it is a flawed practice to attempt to 

use a "generic" approach. 

Response #21 

The consultants did not use a “generic” approach to estimate the total costs of $493 million for 

FCCUs’ wet gas scrubbers. As required under the Statement of Work, the consultants conducted 

site specific analysis for each FCCU at the six refineries and gathered costs information for each 

individual FCCUs from the manufacturers. As shown in the final report of Module 3A, the 

consultants included the following items in their cost estimation: 

• Categorized costs include: 

o Demolition and decommissioning 

o Civil/concrete 

o Structure 

o Equipment 

o Piping and Mechanical 

o Electrical and controls 

• Miscellaneous line items include: 

o Contractor overhead, typically 8 % of direct field labor (DFL) 

o Contractor field supervision, typically 12 % of DFL 

o Mobilization/demobilization, typically 10 % of DFL 

o Overtime/productivity factor, typically 12 % of DFL 

o Freight and shipping, typically 8 %, of materials 

o Sales tax, typically 7 % of materials 

o Commissioning and operating spares, typically 5 % of materials 

o Startup/initial fill material, typically 2 % of materials 

o On-site training/startup assistance, depends on project 

o Front-end engineering design, depends on project size 

o Project management, depends on project size 

o Design development allowance, 10% of total 

o Contingency, 25-40% applied against the bottom-line capital cost estimate 

The “generic” approach that the consultants followed was the Discounted Cash Flow (DCF) 

methodology provided by SCAQMD staff to estimate the cost effectiveness factor. This cost 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 199 November 2, 2010 

effectiveness methodology is consistently used in the AQMPs and in all the rules and regulations 

developed by the SCAQMD. 

Comment #22 

Adequate consideration needs to be given for plot space concerns. 

Response #22 

Plot space concerns were addressed in the consultants’ report, section H: 

“Wet gas scrubber equipment footprints and space requirements for the FCCUs and the 

SRU/TGTUs are shown in the confidential appendices for each refinery where measures 

have been selected. These specifications have been compared with the plot plans 

provided by the respective refineries, and where applicable, are presented in the costing 

workbooks.” 

Comment #23 

Regarding Emerachem technology, the fact that the precious metal (presumably a platinum 

group metal) can be reclaimed at the end of the useful life of the catalyst does not in any way 

suggest that this is an "investment". Reclaiming the metal is a significant cost and the reclaimed 

material only exists as a partial "credit" against the purchase of fresh catalyst. The initial 

purchase price of the metal is only actually recovered when the plant is shut down for good, and 

the value of the metal can be higher or lower than the original purchase price. 

Response #23 

Staff is not clear on the term “investment” used by the commenter and is not certain about the 

purpose of the comment. In Measure M13, the costs to purchase the fresh catalyst system 

($1,800,000) are included in the quote from Emerachem. The consultants also included the costs 

for catalyst change ($420,000) quoted by Emerachem. The consultants gave a salvage value 

(credit) of merely $50,000 to the Emerachem control system at the end of the equipment life. In 

lieu of Emerachem, the facility may select to install a wet gas scrubber. In Measure M17, a wet 

gas scrubber would initially cost approximately $5 million but has a salvage value of $300,000. 

(Measure M13 and Measure M17 were not to control the same SRU/TG however the costs cited 

above can only be used qualitatively) 

Comment #24 

Project timing estimates made by the contractor do not reflect realistic logistical and/or market 

pressures resulting from multiple refineries and other industries pursuing similar technologies 

during a closely concurrent timeline. 

Response #24 

Such timing estimates will be given further consideration as part of the staff analysis. 

Comment #25 

Inadequate information to substantiate the 5 – 10 ppm performance of the wet gas scrubbers 

designed for the SRUs/TGTUs. The lack of substantiation beyond the vendor sales literature is 

highly questionable. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 200 November 2, 2010 

Response #25 

Staff recently received the most recent CEMS data (6 months of 1 hour average data) from the 

Wyoming Department of Environmental Quality which indicated that the DynaWave wet gas 

scrubbers installed and operated since 2004 at Sinclair Refinery in Wyoming can achieve the 

performance levels recommended by staff. 

Comment #26 

The cost effectiveness for this source category (SRU/TG) is on average high (> 30k$/ton) in 

comparison to the FCCU source category and appears to include higher variability, making a 

comprehensive review all that more important. WSPA requested and did not receive specific 

data used by the consultants to arrive at the cost effective conclusions reported. In some cases it 

appears that the technology vendor has provided promises of very high control efficiency and 

what appear to be artificially low capital cost estimates – all at no risk whatsoever to 

themselves. This is particularly true of this source category where the proposed BARCT vendors 

have no experience 

with installation in refineries, which makes their cost estimates highly suspect. 

Response #26 

Staff has recently removed the emission reductions and associated costs for Refinery #4 and #5 

because of the unfavorable cost effectiveness (>$50K per ton). The cost data and performance 

levels proposed by the consultants for the wet gas scrubbers for Refinery #2 and #6 are reliable, 

substantiated by the achieved-in-practice performance of the wet gas scrubbers at Sinclair 

refinery in Wyoming. Staff currently does not have any achieved-in-practice data from 

Emerachem catalysts technology for Refinery #3 but Emerachem provided the consultants with a 

guarantee letter and the consultants also considered a wet gas scrubber for Refinery #3 in their 

confidential analysis. 

Comment #27 

WSPA would agree that the proposal to maintain the existing 40 ppm limit on the sulfur content 

of fuel gas is appropriate. Further WSPA notes that the current US-EPA New Source 

Performance Standard (adopted in April 2008) has a limit that is approximately four times 

higher. 

Response #27 

Staff appreciates the comment and continues to maintain that the 40 ppm on the sulfur content of 

fuel gas is appropriate.
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

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Proposed Amended Regulation XX Part I - 201 November 2, 2010 

Responses to Chevron’s Comments Received on July 14, 2009 

Comment #1 

It is inappropriate for the District to aggressively pursue SOx shave for PM2.5 attainment. The 

current trend of PM2.5 is declining and does not warrant a SOx shave that is estimated to cost 

industry over one billion dollars. 

Response #1 

For a market based incentive program, staff is required by the H&S codes to conduct periodic 

BARCT reassessment and demonstrate equivalency with command-and-control rules which 

would otherwise be developed as a result of BARCT reassessment: 

“...achieve an equivalent or greater level of emission reductions at an equivalent or 

lower cost as would have been achieved under a command-and-control rule” 

It should be noted that SOx is a significant building block of PM2.5. Chemical speciation of 

PM2.5 samples indicated that in the South Coast Air Basin 25% of the ambient PM2.5 is 

attributed to contribution from sulfates. Furthermore, SOx reductions are highly effective in 

reducing ambient PM2.5 levels as compared to other primary and secondary contributors to 

PM2.5 formation (1 tons SOx = 1.5 tons PM2.5 = 15 tons NOx). Therefore, the reductions of 

SOx are essential for the basin to meet the federal annual standard of PM2.5 by 2015 and the 

federal 24-hour average standard of PM2.5 by 2020. As indicated in the 2007 AQMP, the 

control strategies included in the Plan to meet the annual PM2.5 standard when fully 

implemented will fall short meeting the 24-hour standard by approximately 30%. Therefore, 

additional reductions above and beyond the control strategies committed in the 2007 AQMP for 

meeting the 2015 annual PM2.5 standard are necessary to meet the 24-hour PM2.5 standard in 

2020. For further information, please refer to Chapter 5 of the 2007 AQMP. 

In addition, it is worth mentioning that the U.S. EPA is proposing to set a new, more stringent, 

one-hour standard for SO2 between 50 – 100 parts per billion (ppb) and revoke the current 24-

hour of 140 ppb and the current annual standard of 30 ppb to further protect public health. 

In addition, the percent reduction in RTCs (60%-65% prior to January 2010, currently revised to 

55%) that staff estimated for the SOx RECLAIM universe as a whole is still much less stringent 

than the percent reduction in emissions (90% - 98%) that staff could impose to specific 

categories of sources such as FCCUs, SRU/TGs, sulfuric acid plant, cement plant, coal fired 

boiler, and glass melting furnaces if staff pursues the command-and-control approach. 

Staff however is sensitive to the costs of the current proposal (approximately $745 million). To 

reduce the cost impacts, staff proposes to spread the potential emission reductions into 6 years 

starting from 2012. Staff also proposes to submit only 3 tons per day reductions to satisfy the 

SIP commitment in Phase 1 (i.e. 3 tpd reductions by 2014). The remaining reductions will be 

submitted later. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 202 November 2, 2010 

Comment #2 

Staff proposal does not reflect a comprehensive environmental impact. A negative impact to 

other environmental media such as water and waste were not discussed. Capital investment to 

manage additional volumes of water demand, wastewater and solid waste generated were not 

included. In addition, the proposal did not include the complexities of attaining necessary 

permits (e.g. NPDES Discharge Permit.) 

Response #2 

Staff is in the process of analyzing the environmental impact for this proposal. In July 2009, 

staff sent a Survey Questionnaire to the effected facilities to gather information on current usage 

of water, wastewater and solid waste generated. A summary of the information received was 

presented to the stakeholders in the August 2009 Working Group Meeting (please see Table 11-1 

in the revised draft staff report). 

In general, there will be an increase in total water demand (264 million gallons per year, or less 

than 1 million gallons per day, for all six refineries)91 due to the proposed control technologies. 

On a relative scale, however the increase however will be small (below 2%) compared to the 

current total water usage at the refineries (16,936 million gallons per year, or 46 million gallons 

per day). Ground water pumping capacity is available for four out of six refineries. Three out of 

six refineries have used recycled water. All 6 refineries are not subject to any cap from the water 

suppliers. The water suppliers indicated to staff that they can supply the additional amount of 

water to the refineries. In addition, the increase in total water demand is 80% below the current 

CEQA threshold of 5 million gallons per day for significance. However, in a spirit of taking 

abundance of caution, CEQA staff classified this project as significant in terms of potable water 

demand. Please refer to the Program Environmental Assessment for further explanation. 

This proposal will generate an additional amount of wastewater ranging from 15 – 50 gallons per 

minute, (or a total of 94 million gallons per year at 6 refineries). The increase in wastewater 

discharge will be small (less than 1%) compared to the current discharge at each refinery which 

varies from 1,000 – 5,000 gpm. Typically, an increase in wastewater discharge in excess of 25% 

would trigger a discharge permit revision. However, since the increase in wastewater discharge 

is significantly less than 25%, the refineries will not need to revise their NPDES discharge 

permits. Staff also believes that the refineries can handle this amount of increase in their current 

wastewater treatment system. Therefore, the impacts on wastewater are less than significant. 

This proposal will generate an additional amount of solid waste depending on how effectively 

the scrubbers are in controlling particulate matters. The consultants estimated about 2,560 tons 

per year increase. The current FCCU fines classified as non-hazardous waste generated from the 

six refineries are approximately 3,348 tons per year. This 67% increase may be trucked to 

several cement facilities in and around the basin (CPCC in Colton, CEMEX in Victorville, TXIRiverside in Oro Grande, National Cement in Kern County, CPCC in Mohave Desert, and 

Lehigh in Tehachapi). 

 

91 In August 2009, staff revised the water demand reported by the consultants for the SRUs/TGTUs using the information 

submitted directly by the manufacturers of the wet gas scrubbers. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 203 November 2, 2010 

As shown in the consultants’ report, and as quoted below, the consultants did include additional 

capital costs for waste and wastewater treatment. In addition, the consultants did include 

additional annual operating costs for additional water, wastewater treatment, and solid waste 

disposal. 

“Added charges for waste or wastewater treatment equipment are included in equipment 

costs unless treatment is performed outside of the boundary limits for the control 

measure. In these cases, the treatment costs have been calculated according to the 

treatment requirements and site-specific unit costs provided by the refineries.” 

Comment #3 

Emerachem technology is not a proven technology. The contractor report does not offer any 

strategy for dealing with the concentrated SO2 stream captured and released later from the 

catalysts, therefore this technology cannot be considered as SOx reduction technology. 

Response #3 

It is true that Emerachem technology has not yet been installed and used in a refinery, and 

therefore there is no achieved-in-practice data available. However, this argument does not 

negate the feasibility of this technology in a refinery application. For BARCT, additional time 

can be provided to allow technology to mature in refinery applications. Furthermore, in addition 

to the Emerachem technology, the consultants provided three additional options to reduce the 

SOx emissions from the three SRU/TGTUs at this refinery that reflect achieved-in-practice 

technologies. In summary: 

• Emerachem technology resulted in about 53 tons/year reduction for SRU#10 and SRU#20 

and a cost effectiveness of $13K per ton, 

• Wet gas scrubbing resulted in about 41 - 44 tons/year reduction for SRU #70 and a cost 

effectiveness of $32K per ton - $45K per ton (data from 2 WGS vendors were considered), 

• Additional 3rd stage Claus units resulted in about 20 tons/year reduction for SRU#10 and 

SRU#20 and a cost effectiveness of $24K per ton. 

If for the sake of an argument, the current scenario (Emerachem for SRU#10 and SRU#20) is 

replaced with other scenarios (3rd Claus units for SRU#10 and SRU#20 & WGS for SRU#70), it 

will result in 64 tons per year reductions instead of 53 tons per year reductions at a cost 

effectiveness of approximately $30K per ton. Implementation of these scenarios will not 

significantly change the overall cost effectiveness of the proposed overall program. 

Comment #4 

The shave methodology was not transparent, was disclosed very late in the process, and did not 

appear to be consistent with the 2005 NOx shave. 

Response #4 

Staff followed recommendations by WSPA and WSPA members to stay consistent with the NOx 

shave methodology that was developed by the District’s staff and agreed upon by WSPA and 

WSPA’s members in 2005. However, there is no requirement to do so. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 204 November 2, 2010 

While there is an agreement in principal to stay consistent with the 2005 NOx shave 

methodology, developing an actual shave methodology that will work for the SOx RECLAIM 

market and is fair and equitable is not a trivial task. To use the 2005 NOx shave methodology, 

staff invested tremendous amount of time and effort to recover the 1997-1998 emissions baseline 

and the starting emission factors in 1993. Using the 1997-1998 emissions baseline and the 1993 

starting emission factors, staff estimated the control factors and RTC reductions as shown in Part 

III of the Draft Staff Report presented in the June 9, 2009 Public Workshop. The RTC 

reductions presented in the June 2009 Staff Report (i.e. 7.09 tpd – 7.68 tpd) were very similar to 

the emission reductions estimated by staff in April 2008 (i.e. 6.73 tpd – 6.77 tpd) based on the 

2005 emission inventory baseline. Staff expects the proposed shave methodology to continue 

being refined throughout the rule making process. 

It should also be noted that the shave methodology was disclosed sooner than in the NOx 

RECLAIM rulemaking effort in 2004-2005. 

Comment #5 

The methodology for development of emission factors was not clear in the report, and the 

background for some of the initial emission factors was not clearly explained. 

Response #5 

The following information was provided to WSPA and the refineries: 

• Clarification of how certain emission factors (starting and new) for FCC’s, SRU’s and 

boilers were derived for individual facility process units was explained and provided in the 

Working Group meetings on July 30, August 13, and August 27, 2009 

• Derivation of the emission factors referenced in Appendix III-A of the Staff Report SOX 

RECLAIM Part III was explained and provided in the Working Group meetings on July 30, 

August 13, and August 27, 2009 

• Facility specific data/calculations were e-mailed directly to the six individual WSPA member 

facilities on July 17, 2009. 

• Staff is always available for additional explanation. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 205 November 2, 2010 

Responses to Tesoro’s Comments Received on July 14, 2009 

Comment #1 

The current proposal goes far beyond what is called for in the AQMP. 

Response #1 

In addition to the 3 tons per day reduction by 2014 SIP commitment stated in the 2007 AQMP, 

for a market based incentive program such as RECLAIM, staff is required by the H&S codes to 

conduct periodic BARCT reassessment and demonstrate equivalency with command-and-control 

rules which would otherwise be developed as a result of BARCT reassessment: 

“...achieve an equivalent or greater level of emission reductions at an equivalent or 

lower cost as would have been achieved under a command-and-control rule” 

As a result of this BARCT reassessment and equivalency demonstration, staff estimates that the 

SOx RECLAIM program can be amended to provide 6.2 tons per day emissions reduction (or 

approximately 64% of RTC reductions) 

Comment #2 

The process for determining BARCT was not well defined. The consultants BARCT 

determinations appear to be generally based on vendor guarantees. The reports do not contain 

adequate information to substantiate the BARCT emission limits that are proposed for each 

source category. 

Response #2 

The consultants and staff followed the BARCT selection process outlined in Part III of the Staff 

Report. The BARCT selection process included five steps: 1) identify technology that can 

achieve maximum degree of reduction, 2) evaluate control effectiveness, 3) conduct a top-down 

cost analysis, 4) conduct an impact analysis for environment, energy and economic, and 5) select 

BARCT. Vendor guarantees are important information for Step 2. In evaluating the consultants’ 

recommendation for BARCT and arriving at the staff proposal for BARCT, in addition to vendor 

guarantees, staff relied on source test data, CEMS data, permitting data, and engineering 

evaluation. Staff believes that adequate information have been provided to substantiate the 

proposed BARCT for all source categories. 

Comment #3 

An analysis of the impact of the proposed shave on the RECLAIM market has not been 

conducted. Because of the potentially dramatic impact that this shave will have on the 

RECLAIM SOx market, Tesoro supports a phased approach to the SOx shave. Since the 2007 

AQMP did not analyze for attainment with the PM2.5 24-hour standard, we recommend that 

further analysis be completed during the PM2.5 Plan Update to determine if additional tons are 

needed for the 2020 attainment. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 206 November 2, 2010 

Response #3 

Additional reductions in SOx emissions beyond and above those committed in the 2007 AQMP 

are needed to meet the federal 24-hour PM2.5 standard in 2020. Although the District has not 

yet developed the control strategies for the 24-hour PM2.5 standard, it analyzed the input of the 

standard as part of the 2007 AQMP. This analysis revealed that the PM2.5 control strategies 

included in the 2007 AQMP will fall short by 30% in meeting the PM2.5 24-hour standard. Staff 

is in the process of conducting a market analysis for the SOx RECLAIM program. To reduce the 

impacts to the SOx market, staff is in agreement with Tesoro and proposes to phase in the 

proposed reduction beginning 2012 through 2017. Staff further proposes that at least 3 tons per 

day of the reductions be phased in by 2014 to meet the SIP, and the remaining emission 

reductions submitted into the SIP at a later date. 

Comment #4 

The costs for implementing the chosen technologies are not adequately considered in the 

consultant reports or in the Staff reports. The report bundles all the measures into an “average 

cost effectiveness” ratio. This “average cost effectiveness” ratio is not an appropriate 

representation of the true cost of the SOx reduction technologies and is misleading. 

Response #4 

Please refer to Response #10 to WSPA’s comment letter received on July 14, 2009 

Comment #5 

There is a significant increase in water demand, wastewater discharge levels and hazardous 

waste generation resulting from use of wet gas scrubber technology. Further analysis of these 

significant environmental impacts should be conducted in the BARCT evaluation. 

Response #5 

Please see Response #2 to Chevron’s comment letter received on July 14, 2009 

Comment #6 

There are a number of unanswered questions concerning the origin of certain assumptions and 

numbers used to calculate the current BARCT numbers and shave recommendations. 

Response #6 

The answers were provided to WSPA and the refineries in the Working Group meetings on July 

30 and August7. Refinery specific data were e-mailed to each refinery on July 17, 2009. Staff is 

always available if further explanations are needed. A summary is provided below: 

Derivation of the starting emission factors 

FCCUs

Starting emission factor = Total emissions (lbs/year) / Total throughput (barrels/year) 

 = (6,033,327 lbs/year) / (115,893 thousand barrels refinery feed) = 52.06 lbs/Mbarrels

Sulfur Recovery Units

Starting emission factor = Total emissions (lbs/year) / Total hours operation (hours/year) 

 = (1,122,050 lbs/year) / (133,764 hours/year) = 8.39 lbs/hrs
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 207 November 2, 2010 

Boilers/Heaters

Starting emission factor = Total emissions (lbs/year) / Total fuel usage (mmscft refinery 

gas/year) 

 = (3,738,879 lbs/year) / (112,105 mmscft/year) = 33.35 lbs/mmscft

Derivation of the proposed new BARCT level for FCCUs 

 Consultants’ proposed level: 

Remaining emissions = 3.52 – (0.58+0.19+0.28+0.20+0.87+0.94) = 3.52–3.07 = 0.45 tpd 

Emission rate = (0.45 tpd x 2000 lbs/ton)/(396 thousand barrels feed/day) 

= 2.27 lbs/thousand barrels 

 Staff’s proposed level: 

Remaining emissions = 3.52 – (0.58+0.28+0.20+0.87+0.94) = 3.52–2.88 = 0.64 tpd 

Emission rate = (0.64 tpd x 2000 lbs/ton)/(396 thousand barrels feed/day) 

= 3.25 lbs/thousand barrels 

Derivation of Tier I factor for heaters and boilers 

Tier I factor for boilers and heaters (external combustion Equip/Incinerator using refinery 

gas) is on Table 2 of Rule 2002 = 6.76 lbs/mmcf = 40 ppmv 

Why is the remaining inventory for heaters and boilers different in Part I and Part III of the staff 

report (1.42 tpd vs. 0.89 tpd)? 

The Tier I allocations shown in Table 4-1, Part I of the Staff Report (0.89 tons per day) 

were for 6 refineries in the basin. The remaining inventory shown in Appendix III-B, 

Part III of the Staff Report (1.42 tons per day) were derived from the 1997-1998 

inventory of all boilers/heaters at all active refineries in 1997-1998. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 208 November 2, 2010 

Responses to BP’s Comments Received on July 14, 2009 

Since BP requested the opportunity to review and highlight the comments for confidentiality 

before the comments are printed in public document, staff will not print BP’s comments or 

responses to BP’s comments at this time. 

Responses to Paramount’s Comments Received on July 14, 2009 

Comment #1 

Unlike the NOx universe, the SOx universe is small enough that the District could come up with 

a plan for the SOx shave that would take into account the technology employed and individual 

opportunities for SOx reductions that are available at different facilities. For the rule to be 

equitable, only facilities that operate certain source categories and do not yet meet the BARCT 

standard should be required to take the BARCT adjustment. Facilities that do not operate 

FCCUs should not be responsible for emission reductions from FCCUs. 

Response #1 

Staff is in agreement with the commenter. The SOx market is very different than the NOx 

market. Eleven facilities in the SOx market are responsible for 94% of the emissions and hold 

about 86% of the RECLAIM Trading Credits. The preliminary draft Staff Report released in 

2008 focused in finding BARCT and emission reductions from the top eleven facilities and 

seven categories of sources. It would be difficult for a facility with no equipment subject to new 

BARCT to reduce SOx emissions. Staff is examining two alternatives: 1) provide an alternative 

percent shave for these facilities, or 2) not shave these facilities at all. For facilities that have the 

2012 RTC holdings higher than the 2012 initial allocations provided to the facilities at the start 

of the RECLAIM program, staff may shave the surplus up to the 2012 initial allocations. Further 

discussions are needed to finalize the proposal. 

Comment #2 

The implementation for the District’s proposal can take 3 years to complete, yet the District 

scheduled for implementing the SOx shave starts with reductions in 2012, which is only 2 years 

from the planned adoption date. Refineries must make modifications during turnarounds that 

typically occur every 3 – 5 years. The implementation date should be moved back to 2014 to 

enable facilities time to pursue these major modifications 

Response #2 

Staff proposed a first shave of 1.5 tpd at the end of compliance year 2012. This 1.5 tpd comes 

from the surplus RTC (Total RTC holdings = 11.7 tpd & actual emissions = 10 tpd). Wet gas 

scrubbers may take may take up to three years to install, therefore staff proposed a second shave 

of 1.5 tpd at the end of compliance year 2013. The remaining shave was proposed to be 

distributed in additional four years from 2014 to 2017. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 209 November 2, 2010 

Comment #3 

Paramount has been significantly left out of recent developments in this rule making process. 

Paramount did not have an opportunity to participate in the consultants’ study and evaluated the 

findings along with major refiners. Paramount suggests that a concerted outreach effort be 

conducted to ensure that all impacted facilities are given the opportunity to understand and 

comment on the District’s SOx shave proposal. 

Response #3 

The recent developments were all publicly notice. The Request-for-Proposals was also posted 

on the District’s web site. Staff conducted a bidder’s conference on July 16, 2008 which was 

posted on District’s web site. Staff’s recommendations were presented to the Governing Board 

at two public meetings on July 11, 2008 and September 5, 2008. There are subsequent public 

consultation meetings, workshops, and working group meetings held where the consultants’ 

recommendations and suggested amended proposals were further discussed. There were ample 

opportunities for the commenter to participate. However, staff did not receive any comments, 

suggestions, or indications of interest from the commenter during this period of time until after 

the consultants’ study was finalized. In addition, it should be noted that most of the information 

and analysis was conducted on a facility-by-facility confidential basis and cannot be discussed 

with the commenter. Staff did send copies of the consultants’ non-confidential reports to the 

commenter as requested on September 2, 2009. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 210 November 2, 2010 

Responses to WSPA’s Comments Received on July 2, 2008 

Western States Petroleum Association 

Credible Solutions • Responsive Service • Since 1907 

Jodie Muller 

Manager, External Affairs and South Coast Region 

July 2, 2008 Via E-Mail and First-Class Mail 

Joe Cassmassi 

South Coast Air Quality Management District 

21865 East Copley Drive 

Diamond Bar, CA 91765-4182 

WSPA Comments on the Preliminary Draft Part I Staff Report - RECLAIM SOx

WSPA appreciates the opportunity to comment on the "Preliminary Draft Staff Report Sox 

RECLAIM Part I Allocations, Emissions & Control Technologies" (the "Report"), and we 

appreciate your patience while we were addressing the other priorities that you had established 

(e.g., the RFP for the contractor project, FCCU SOx reduction catalyst additives, etc.). WSPA’s 

detailed comments are attached to this transmittal email, in the form of comments and suggested 

edits provided directly on the draft Staff Report. 

WSPA's attached detailed comments speak for themselves, and we need not summarize them in 

this transmittal. However, there are a few overarching issues that we would like to specifically 

call to your attention: 

1. The draft Report references 2007 AQMP Control Measure CMB-02 as being the impetus for 

the BARCT reassessment, but the Report does not accurately describe the legal basis for this 

rulemaking effort, nor does it address the process by which the BARCT reassessment will be 

conducted. While the Report provides an overview of existing control technologies and suggests 

new, potentially feasible emission rates or limits, it does not provide detail regarding the process 

the District will use to identify new 2010 facility annual allocations, does not indicate how the 

District will determine the feasible reductions to be achieved by the "shave", and does not 

address the need for a reasonable compliance margin. 

An understanding of, and agreement with, the methodology for developing BARCT levels, and 

the resultant potential shave, needs to precede most of the other work. The facilities that will be 

subject to any SOx shave need to know exactly how proposed revised allocations and the 

proposed shave will be calculated. Only once the process has been agreed to should the District 

move ahead with reassessing the BARCT levels. 

Comment #1 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 211 November 2, 2010 

2. The report alludes to the possibility of incorporating both the reassessment of the BARCT 

levels under the SOx RECLAIM program (as proposed in 2007 AQMP CM CMB-02) and the 

concept of facility modernization (from 2007 AQMP CM MCS-01) into a combined overall 

effort to reduce SOx emissions. However, the Report does not explain the process for doing so 

or why it might be appropriate to include a facility modernization analysis with this effort. 

WSPA is concerned about the potential for blurring the distinction between a BARCT 

reassessment and the possibly similar assessment of facility modernization. Since there will 

likely be overlapping issues, it is very important that the District independently develop, and 

reach consensus on, the process for implementing each control measure. If both measures are 

to be considered simultaneously, then the Report must clearly show how each measure will 

work in tandem with the other (and the feasibility of such an approach) before allocation levels 

are established. 

3. The Report attempts to tie the potential reduction of RECLAIM SOx allocations (i.e., a 

reduction of SOx emissions) to PM air quality but does not establish the necessary basis for a 

linkage between the two. The Report cannot be based on an assumed relationship between SOx 

emissions and ambient PM10 or PM2.5 levels; rather, it must describe and provide evidence for 

how SOx emissions contribute to ambient particulate matter concentrations and how the 

anticipated SOx emission reductions will affect ambient air quality. 

4. The "Proposed BARCT Levels and Emission Reductions" section of chapters three through 

nine includes detailed conclusions with respect to the applicability of various emission control 

technologies and the resultant BARCT levels for the various source categories in the SOx 

RECLAIM program. These conclusions are premature and unsubstantiated, and their inclusion 

in the report is not appropriate given that the District is planning to hire one or more expert thirdparty contractor(s) to conduct thorough engineering evaluations and cost estimates of potential 

SOx emission reduction technologies. WSPA is very concerned that the Report’s preliminary, 

and largely unsubstantiated, conclusions will become benchmarks against which the contractors' 

work products might be evaluated and effectively prejudge the expected conclusions rather than 

foster an independent analysis. 

5. Due to the significance of this SOx BARCT reassessment program and the issues that we 

have identified with the draft Report, WSPA believes that the Report must be substantially rewritten. The issues WSPA raises here and in the attached detailed comments cannot (and should 

not) be handled though responses to comments or preparation of a supplement Report, either of 

which would require the reader to read and understand two or more separate and likely 

conflicting documents. WSPA has tried to present its detailed comments in a way that can serve 

as a useful guide for rewriting the draft Part I Report, and hopes that District staff take advantage 

of our suggestions in that manner. 

Again, WSPA appreciates the opportunity to submit these comments on this important effort. 

We ask that our detailed comments and this transmittal letter be included in the record for this 

rulemaking. WSPA looks forward to working with the District as this effort progresses, and we 

look forward to commenting on future drafts of the Part I and Part II Staff Reports for this 

rulemaking, as well as on any proposed rule amendments and other related regulatory materials. 

Comment #3 Comment #4 Comment #5 

Comment # 2 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 212 November 2, 2010 

Please do not hesitate to contact me if you have any questions. 

Sincerely, 

Jodie Muller 

Enclosure -- WSPA Comments 

cc: Gary Quinn, P.E. 

Laki Tisopulos, Ph.D., P.E. 

Minh Pham, M.S., P.E. 

Staff’s Responses to WSPA’s Comments

Response #1 

Staff appreciates WSPA’s comments and suggested edits on Part I of the Preliminary Draft Staff 

Report. Staff will respond to all WSPA’s comments, review WSPA’s edits, and if appropriate, 

will revise the Draft Staff Report. 

Regarding WSPA’s detailed comments, staff will respond to the key issues and retain the 

detailed comments in the Administrative Records of this amended rule. This approach is taken 

to reduce the bulk of the detailed comments/responses portion of the Draft Staff Report. 

First, staff would like to direct WSPA to the legal basis of this rule making effort described in 

Section 1.1 of the Draft Staff Report – Legislative Authority. Secondly, with all due respect, 

staff disagrees with the sequence of approaches recommended by WSPA for this rule 

amendment. Staff ‘s seven-step approach for this rule amendment is described below, in 

sequence: 

1. Conduct an assessment of allocations and emission baselines; 

2. Conduct a review of control technologies; 

3. Identify areas of potential emission reductions, focusing on these areas with greatest potential 

reductions; 

4. Conduct site-specific evaluation of control technology feasibility and costs 

5. Assess BARCT 

6. Re-examine the potential emission reductions in Step 3, taking into consideration the final 

emission reductions, and the amount of allocation shave while maintaining the integrity, 

equity, and operational characteristics of the SOx RECLAIM program; and 

7. Amend appropriate rules in Regulation XX. 

The first three steps were presented in Part I of the Preliminary Draft Staff Report and several of 

staff’s presentations at the SOx RECLAIM Working Group Meetings. The last four steps are 

presented in Part II of the Draft Staff Report, and will be developed in parallel with the 

contractors’ work on the proposals 

Response #2 

For this rule amendment, BARCT reassessment will be the basis that used to assess the emission 

reductions and the allocation shaves. The concept of facility modernization, if used, may only 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 213 November 2, 2010 

influence the timing of the allocation shave. However, at this stage, staff expects that the facility 

modernization concept will not play a significant role in this rule amendment effort. 

Response #3 

Please refer to Appendix 5 of the 2007 AQMP for the evidence of how SOx emissions contribute 

to ambient particulate matter concentrations, and how the anticipated SOx emission reductions 

will affect ambient air quality. 

Response #4 

Staff ‘s seven-step approach for this rule amendment is described in Response #1. The first three 

steps were presented in Part I of the Preliminary Draft Staff Report and several staff’s 

presentations at the SOx RECLAIM Working Group Meetings. To assist staff in the BARCT 

assessment, expert third-party contractor(s) conduct a thorough, independent, site-specific 

engineering evaluations and cost estimates of potential control technologies in Step 4. The 

results of the contractors’ analysis will be used in Step 5 and Step 6. Staff will develop Part III 

of the Draft Staff Report Staff to cover the information in the last four steps in parallel with the 

contractors’ work in Step 4. 

Response #5 

Staff will respond to all comments received and revise the Draft Staff Report appropriately. 

Regarding WSPA’s detailed comments, staff will response to the key issues and retain the 

detailed comments in the Administrative Records of this amended rule. This approach was 

selected to reduce the bulk of the detailed comments/responses portion of the Draft Staff Report. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 214 November 2, 2010 

Responses to BP’s Comments Received July 1st, 2008 

VIA E-Mail 

July 1st, 2008 CONFIDENTIAL BUSINESS INFORMATION 

Ms. Minh Pham 

Air Quality Specialist 

Planning, Rule Development and Area Sources 

South Coast Air Quality Management District 

21865 E. Copley Drive 

Diamond Bar, CA 91765 

Subject: 2nd Round of Comments on RECLAIM SOx Shave Staff Report Part 1 

Dear Ms. Pham 

BP appreciates the opportunity to comment on the draft Part 1 of the staff report for the 

RECLAIM SOx shave. I provided some initial comments on this report back on April 29th. 

Below are some additional company specific comments for these facilities that are not 

appropriate to share with WSPA. Please note that some of this information is to be treated as 

business confidential. 

Refinery

• I suggest removing the sentences related to the CanSolv scrubbing system installed at the 

Cherry Point SRU mentioned in Section 5.3.3.2 of the report. It is true that the unit was 

started in July of 2006, but it only operated for about 4 months due to equipment 

problems outside of the CanSolv system. It is still not operating. It was also not designed 

to achieve 10 ppm as stated. In fact, the unit is designed to meet what the state regulatory 

agency determined to be BACT – 250 ppm SO2 12-hour rolling average (same as NSPS 

Subpart J/Ja) and it has a 135 tpy mass limit annually which I believe translates to 150 

ppm. The following is an excerpt from the from the Marsulex Agreement for the design 

of the unit: 

SO2 Removal. The concentration of SO2 in the treated gas (stack gas) shall be less than 

250 ppmv, oxygen fee, dry basis, (no nitrogen adjustment). 

BP West Coast Products, LLC 

6 Centerpointe Drive 

La Palma, Ca 90623 

Telephone: +1 (714) 670-5493 

Comment #1 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 215 November 2, 2010 

Calciner

• Similar to the request above, we respectfully ask that you eliminate the brief discussion 

about the BP Cherry Point Calciner control system in section 8.3.2 of the report. There 

are two reasons for this request. First, much of the basic information is inaccurate such 

as the permit chronology and statements suggesting that SO2 was reduced as a result of 

the installation of a wet ESP (specifically designed for particulate and acid mist removal, 

not SO2). Any apparent SO2 reduction was likely coincident with this change but due to 

something else. The likely cause of inaccuracies in the chronology is the result of having 

multiple calciners undergoing modifications at different times, but none of the dates 

mentioned line-up correctly with the specified modifications. To clarify all the permit 

history would require an expansive discussion without any real value added to the report. 

There is also ‘test’ data presented that the unit met 10-12 ppm SO2 in the stack. I did not 

see any such test data when I reviewed source test results. 

Secondly, the data from the Cherry Point calciner does not necessarily support the 

conclusion that the Wilmington calciner emission performance could be improved. 

While it is true that the stack concentration is consistently lower at Cherry Point, the 

removal efficiency is not any better. You list an inlet concentration range at Cherry Point 

of between 1125 and 1425 ppm. This information appears accurate based on some tests 

and translates into an inlet mass of 1200 – 1500 lbs/hr. However, as provided in our 

survey to SCAQMD, our analyzer data for 2007 shows inlet mass ranging at about 5200 

lb/hr (2700 ppm) at Wilmington. I am not sure why the different levels of sulfur in the 

inlet exist, but this explains the slightly higher removal efficiency reported at Wilmington 

mentioned previously in my comments. 

None of this information suggests that wet scrubbing, as an option to the existing dry 

scrubbing system at Wilmington, should not be explored in the 3rd-party engineering 

analysis in Part II of the staff report or discussed generically in this section. I also do not 

have a concern if it is mentioned that such a system is installed and operating at the BP 

Cherry Point refinery. However, to avoid having to rewrite the complex permit history 

and trying to explain why Cherry Point has a consistently lower stack concentration while 

Wilmington has higher removal efficiency, I suggest removing the discussion of the 

Cherry Point performance in its entirety. 

If you have any questions regarding these comments, do not hesitate to call me at (714) 670-

5493 or reply to this e-mail. 

Sincerely, 

Miles Heller 

Air Issues Specialist 

Comment #2 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 216 November 2, 2010 

Staff’s Responses

Note that the commenter did not specifically identify or justify which information was 

confidential; therefore the comments will be treated as non-confidential. 

Response #1 

Staff does not agree with BP’s suggestion to remove Section 5.3.3.2 of the Preliminary Draft 

Staff Report related to the Cansolv scrubbing system installed at Cherry Point Refinery’s Sulfur 

Recovery Units. 

Staff acknowledges the information provided by BP that 1) the Cansolv scrubber has been 

designed to a level less than 250 ppmv, 0% O2, currently required by NSPA Subpart J/Ja or 

MACT II, and 2) is subject to a mass annual limit of 135 tons per year, translated to 150 ppmv 

SOx, as BP. However, staff believes that it is not uncommon for a system to achieve levels 

below the designed levels. This fact is supported by the following examples: 

• Two Cansolv scrubbers were designed for a FCCU and a FCU at Valero’s Delaware City 

Refinery. The designed outlet SOx concentration is 25 ppmv. These scrubbers have 

been in operation for more than a year, and have actually achieved levels of 2 ppmv SOx 

outlet concentration on a continuous basis. 

• Two DynaWave scrubbers were installed at Sinclair oil refineries in Wyoming and 

designed to meet less than 250 ppmv limit of MACT II and NSPS Subpart Ja. These 

scrubbers have been in operation more than a year and actually achieved a level below 1 

ppmv (e.g., 0.3 ppmv which represents the lower detection limit of stack testing.) 

Staff has provided accurate information in Section 5.3.3.2 related to the Cansolv system in the 

Preliminary Draft Staff Report, and as such, will not remove this section. However, staff will 

add a footnote to reflect the current non-operational status of the system as indicated by BP. 

Response #2 

Staff does not agree with BP’s suggestion to eliminate Section 8.3.2 of the Preliminary Draft 

Staff Report related to the Cansolv scrubbing system at Cherry Point Refinery’s coke calciners. 

Staff’s responses to several issues stated in Comment #2 are as follows: 

• Permit Chronology 

Following BP’s suggestion, staff will not discuss the operational history and permit 

chronology of the calciners at BP Cherry Point Refinery. As such, staff removed the dates 

(e.g. 1984, 1994, 2001) mentioned in this section. 

 

• Accuracy of Emissions and Performance Information 

Staff believes that it is important to state relevant public information related to the 

performance of the wet scrubbers/wet ESPs for the calciners at Cherry Point Refinery 

accurately. The information provided in the Preliminary Draft Staff Report was all correct 

and accurate, and will be repeated below with specific references provided: 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 217 November 2, 2010 

Information Reference

The inlet SOx concentration from the 

calciners at Cherry Point Refinery 

ranges from 1125 ppmv – 1425 ppmv 

November 1, 1977 PSD Applicability 

Determination – ARCO Petroleum 

Permit limit concentration of 160 

ppmv and 90% control efficiency 

previously given to the wet scrubber 

Northwest Clean Air Agency, Notice of 

Construction Worksheet for BP Cherry Point 

Refinery (NOC #985), dated December 2006 

Permit limit concentration of 35 ppmv Northwest Clean Air Agency, Air Operating 

Permit of BP Cherry Point Refinery 

Control efficiency of the control 

system including wet scrubber and wet 

ESP 

Estimated from inlet and permitted levels: 

(1 – (35 ppmv / 1125 ppmv))*100 = 96.9% 

(1 – (35 ppmv / 1425 ppmv))*100 = 97.5% 

Test results showing 10 – 12 ppmv From a paper titled “Eliminating a Sulfuric 

Acid Mist Plume from a Wet Scrubber on a 

Petroleum Coke Calciner”, Brown & Hohne. 

This paper indicated an average annual SOx 

concentration of 18 ppmv and a SO2 removal 

efficiency of 99%. 

Staff acknowledges that the main function of the wet ESP is to further control sulfuric acid 

mist emissions and eliminate visible plume. This fact was already mentioned in Section 

8.3.2 of the Preliminary Draft Staff Report. However, the permit limit for SOx was reduced 

from 160 ppmv to 35 ppmv, and this fact speaks for itself about the concurrent effect on SOx 

removal efficiency. 

• Stack Concentration (ppmv), Removal Efficiency (%), and Emission Rate (lbs/ton) 

The control efficiencies (98% - 99%) for Wilmington’s coke calciners were based on actual 

outlet concentrations (27 – 52 ppmv) and inlet concentration (2700 ppmv). The control 

efficiencies (96.9% - 97.5%) for Cherry Point Refinery’s coke calciners were based on 

permitted outlet concentration (35 ppmv) and inlet concentrations. When the actual outlet 

concentrations are used (10-12 ppmv), the control efficiency for Cherry Point Refinery’s 

coke calciners will approach 99% or more. 

The emission rate of Cherry Point Refinery’s coke calciner (0.14 lbs/ton) is lower than those 

at BP Wilmington (0.56 lbs/ton – 0.89 lbs/ton). The Tier I emission rate for BP Wilmington 

calciner was set high at 2.47 lbs/ton. In addition, the current reported production rate of 

Wilmington’s coke calciner is approximately 22% higher than the past production rate 

reported by BP and used in Tier I allocation calculation. To balance the increase in 

production rate and to meet a potential lower BARCT level, staff strongly believes that BP 

should improve the performance of its control system at Wilmington’s coke calciner. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 218 November 2, 2010 

Responses to Valero’s Comments Received July 1st, 2008 

-----Original Message----- 

From: Gonzales, Susan [mailto:Susan.Gonzales@valero.com] 

Sent: Tuesday, July 01, 2008 1:26 PM 

To: Minh Pham 

Subject: FW: Valero Del City 

Importance: High 

 

Hi Minh -listed below are the comments on the preliminary draft report. The comments 

are from our Valero Delaware City environmental department. 

 

I've attached the document portion that I had them review. Thanks. Sue 

 

Valero Delaware City Refinery Comments:

 

On page 1, in addition to Valero DE City, Motiva DE City is listed. The Motiva entry is 

a duplicate. We are the old Motiva DCR. The Valero DCR entry contains two footnotes 

(#2, #5). #5 footnoted below the table has an (a) and a (b). The (b) references a scrubber 

on an HF Alkylation Unit...and I don't know what this is referring to (some other Premcor 

refinery?) because we do not have an HF Alkylation Unit. I'm also not sure what the 

65% reduction is referring to. The two regenerative WGS units on the FCCU and FCU 

here in DE City were designed to reduce emissions by 99% at the FCU and 97% from the 

FCCU. 

 

Page 3 mentions inlet flow volume to the WGS. The design inlet volumes from the final 

permit applications are 258,200 scfm for the FCU and 442,400 scfm for the 

FCCU. These values are not on a moisture corrected (dry) basis. I also have no 

knowledge of the statement in the last sentence about the FCCU being "twice bigger than 

the largest refinery in the District." 

Staff’s Responses to Valero’s Comments

Staff contacted Delaware Department of Natural Resources and Environmental Control 

(DNREC)’s Division of Air Waste Management to clarify about the name of the refinery and the 

status of operation. DNREC’s staff confirmed that Valero had recently bought Delaware City 

Refinery from Motiva. DNREC’s staff also indicated that there have been several ownership 

changes for this Delaware City Refinery; however this refinery is still referred to as “Premcor 

Refinery” on various documents such as permits. 

 

Based on the information provided by Valero and DNREC, staff has:1) deleted the duplicate 

entry for Motiva in Table 3-3; 2) made a clarification in footnote #5 that Premcor Delaware City 

Refinery is now owned by Valero; 3) deleted several wordings in footnote #5 which referred to 

HF alkylation unit and 65% reduction (which was the estimated overall facility emission 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 219 November 2, 2010 

reduction from DNREC;) 4) included the two flow rates for FCCU and FCU in Paragraph 3.3.2.3 

of the Staff Report; and 5) included additional information provided by DNREC that the two 

scrubbers have indeed achieved SOx levels of 1 ppm - 2 ppmv, corrected to 0% O2, on a 

continuous basis. The scrubber system for the FCCU is in operation for about 1.5 years, and the 

scrubber system for FCU is on line for more than 2 years. Based on a comparison on the exhaust 

flow rates from the FCCUs and feed rates, Delaware Refinery’s FCCU is about twice larger than 

the largest FCCU in the District. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 220 November 2, 2010 

Responses to Rhodia’s Comments Received April 29th, 2008 

Rhodia Inc. provided comments and edits on Chapter 6 of the Preliminary Draft Staff Reports – 

Sulfuric Acid Manufacturing Process on April 20, 2008. Staff appreciates the comments and has 

incorporated many of Rhodia’s edits in the newly revised version of the Draft Staff Report. 

Responses to Rhodia’s Comments Received November 25th, 2008 

Comment #1 

State law prohibits the District from setting BARCT levels without considering the relative 

environmental and economic impacts on each affected source category. The Draft Report fails to 

make any findings at all concerning (1) the relative cost-effectiveness of requiring the proposed 

SO2 controls at a sulfuric acid plant like Rhodia instead of requiring more reductions from 

sectors responsible for greater PM2.5 and/or SO2 contributions; (2) relative PM2.5 reductions 

available from tighter controls on sulfuric acid plants versus other sectors/sources; (3) relative 

costs and environmental benefits of imposing more aggressive controls directly on PM2.5 

sources rather than on sources of SO2 (which is only a precursor to PM2.5); or (4) whether 

imposing stricter PM2.5 and/or SO2 controls on other sectors may cause less overall adverse 

economic impact than imposing those controls on Rhodia. For example, requiring additional 

reductions from highly emissive direct sources of PM2.5 very well could result in a greater and 

more cost-effective reduction of PM2.5 than driving down BARCT levels for sulfuric acid 

regenerators, who are a very small source of PM2.5 in the South Coast Air Basin. In any event, 

reciting control costs and cost-per-ton figures in a vacuum tells the District nothing about 

whether tighter regulation of other sources may be less economically burdensome and/or more 

effective at producing PM2.5 attainment by 2015. Accordingly, the Draft Report fails to provide 

a complete BARCT analysis. 

Response #1 

Staff recognizes that for a BARCT assessment to be made state law requires 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 sources. (H&S Code 

§40406) However, it should be noted that the results provided in the subject report is not the 

BARCT assessment but rather input for the staff to generate a recommended BARCT for the 

various equipment subject to SOx RECLAIM. 

Comment #2 

Since the District began its effort to investigate and redefine BARCT for SOx from sulfuric acid 

plants and other sources, both the credit markets and the broader economy have suffered major 

downturns. Financing for major projects is extremely difficult to secure, and most economic 

analysts predict that these credit issues will extend into 2009 and potentially 2010. The Draft 

Report makes no mention of these changed economic circumstances, and fails to discuss the 

potential impacts of tightening BARCT levels at a time when sources could find it difficult or 

impossible to complete the required capital projects by 2015. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 221 November 2, 2010 

Response #2 

Addressing the current economic situation’s impact on financing major projects is outside the 

scope of this report. Such dialogue has transpired as part of the SOx Working Group. Staff will 

try to schedule implementation of these projects with the lowest possible financial impacts while 

maintaining the 2015 emission reduction goals as presented in the 2007 AQMP. 

Comment #3 

AQMP Control Measure CMB-02 is a measure designed to secure appropriate SOx reductions 

pursuant to RECLAIM, primarily (as the AQMP describes) from refineries. It is not a control 

measure designed to achieve PM2.5 reductions required for District wide attainment. While the 

District certainly has an interest in achieving PM2.5 attainment in the South Coast Air Basin, 

Control Measure CMB-02 makes no mention of requiring SOx reductions as a PM2.5 reduction 

strategy. If the District’s aim is to secure sufficient PM2.5 reductions to achieve PM2.5 

attainment by 2014, it must fairly compare the costs and benefits of securing PM2.5 reductions 

from the universe of PM2.5 sources throughout the Basin, not disproportionately from a handful 

of SOx RECLAIM sources. 

Response #3 

The staff report will address the relationship between SOx and PM2.5. However, the commenter 

is referred to such documents as Appendix V of the 2007 AQMP for a much more detailed 

discussion of this relationship. 

Comment #4 

The capital cost estimates in the Draft Report (summarized in Table 3 on page 8 and in Table R2 in Section V.L. of the confidential appendices) appear to be inaccurate, and vary from each 

other by over $6 million. Rhodia has been unable to verify the sources of these equipment cost 

estimates, both of which are well below the likely installed equipment costs of installing a caustic 

scrubber. Recent experience within our company and throughout the market suggests to us that 

the installed cost of a scrubber is approximately $15 million. For these reasons, the cost 

effectiveness values in Table 4 on page 9 are also too low, and do not reflect real world costs. 

Moreover, in Section V.M., Table R-3., the operating cost estimates for caustic makeup also 

appear to be too low, given that current market value for caustic is approximately $1,000 per ton 

(100% NaOH). These data errors undermine the Draft Report’s cost effectiveness conclusions 

on page 10, and suggest that actual capital and operational costs may be significantly higher 

than the numbers cited. Because California law mandates that the District make proper costeffectiveness findings before setting or changing BARCT, Rhodia strongly recommends that the 

District take the PDSR off the December calendar, ask its vendors to document the sources for 

all of the cited cost data, and work with Rhodia to resolve the data discrepancies before moving 

forward. 

Response #4 

The consultant has conducted a very thorough analysis with respect to the cost analysis of the 

subject equipment. However, given the very low cost effectiveness derived by the consultant the 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 222 November 2, 2010 

costs would have to be several-fold greater than assessed in order for the cost-effectiveness to no 

longer being attractive. 

Comment #5 

The Draft Report assumes that Rhodia could install a new caustic scrubber as soon as 2011. 

Rhodia estimates that, if it were required to install a new scrubber, it would not be ready for 

operation for at least 2 to 3 years after initial funding of the project. Even in a best-case 

scenario, emissions reductions from any new scrubber installed at Rhodia may not be available 

to help PM2.5 attainment until 2012 or later, depending on when the District approves the 

BARCT revision. The Draft Report fails to address the relative costs and benefits of requiring 

SO2 emissions reductions that would not yield PM2.5 reductions until those years, nor does it 

address whether reductions in other sectors may be more timely and cost-effective. 

Response #5 

The SOx emission reduction goal of at least 2.9 tons per day needs to be made prior to 2015. 

Staff will assess the feasibility of achieving this emission reduction in the indicated timeframe as 

part of the rulemaking process, taking into consideration the time needed to install control 

equipment. 

Comment #6 

In the first paragraph of page 4 of the Draft Report, we would recommend adding the following 

underlined language: “Historically double absorption plants have needed no further SO2 

reduction before the tail gas is emitted to the atmosphere, because their emissions are typically 

well below the New Source Performance Standard of 99.7% conversion or 4 lbs. per ton.” In 

the second paragraph on page 4, we would recommend deleting the word “pentoxide” from the 

catalyst description. Extensive research conducted by Rhodia’s catalyst supplier indicates that 

the vanadium is in a form of complex salts rather than vanadium pentoxide. 

Response #6 

The consultant opted not to include the language in the subject report. If appropriate staff may 

include such language in the staff report. 

Comment #7 

In Figure 1 on page 6, “Facility 1, 2, 3”, should be changed to “Facility A, B, C,” respectively, 

to be consistent with the rest of the Draft Report. In the confidential section of the Draft Report 

Response #7 

The consultant corrected the facility identification as indicated by the commenter. 

Comment #8 

Finally, though Rhodia provided extensive comments and edits to the last draft of the PDSR, 

none of those comments appear to have been incorporated into the version that was posted on 

the District’s website. Rhodia also provided comments to an earlier version of the PDSR, but 

only a fraction of those comments appears to have been incorporated into the current version. 

Indeed, the District has failed to provide any response at all to most of Rhodia’s comments on 

the PDSR. Rhodia is concerned that the District may be on a path to adopting a new and stricter 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 223 November 2, 2010 

set of BARCT requirements without sufficiently considering or incorporating Rhodia’s written 

comments. 

Response #8 

Staff will respond to such comments as part of the staff report development. 

Responses to WSPA’s Comments Received April 29th, 2008 

Comment #1 

Part I, as drafted, contains numerous examples of the topics that are apparently intended to be 

covered in Part II. In addition to being premature, the discussion of these items in Part I is 

largely unsubstantiated and lacking adequate detail. WSPA strongly suggests that contents of 

the Part I Staff Report should conform to the scope specified in the above paragraph. 

The methodology by which the District will actually develop the recommended RECLAIM SOx 

allocations shave is a critical discussion that should be included up-front, in the Part I Staff 

Report. (There is currently no mention of this essential topic.) 

WSPA notes that the revised draft RFP for the third-party contractor project mentions that the 

Part II Staff Report will include "... a discussion on the process for reassessing BARCT, 

appropriate BARCT levels, emission reductions (aka allocations shave) and cost effectiveness 

for RECLAIM program (sic)." However, we submit that an understanding of, and agreement 

with, the methodology for developing a recommendation for an allocations shave – along with 

the necessary compliance margin – needs to proceed most of the other work (e.g., the third-party 

contractor project). In fact, arguably, we have already gotten "ahead of ourselves". 

The methodology for the NOx shave proved to be very complex. Because we would expect a 

similar level of complexity with regard to SOx, the discussions regarding process cannot wait for 

a Phase II Staff Report. We should not delay those discussions any further – they need to 

commence now. 

Response #1 

Staff appreciates the concerns raised by WSPA in having an understanding of the SOx shave 

methodology. In recent meetings with the refineries and as requested by the refinery task force, 

staff has agreed to provide an estimate of SOx RTC reductions following the methodology that 

was used in the January 2005 NOx RECLAIM amendment. However, as in the January 2005 

NOx RECLAIM amendment, further discussions are warranted (e.g. BARCT assessment) prior 

to finalizing the RTC reductions. 

Comment #2 

The decrease in the number of RECLAIM SOx facilities warrants some discussion and analysis. 

In particular, there would be interest in knowing whether or not any facilities have ceased 

operations, and, if so, why they did. 

Response #2 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 224 November 2, 2010 

Please refer to the Annual RECLAIM Audit Reports presented to the AQMD Governing Board 

on an annual basis in March. The most recent reports were presented to the Governing Board for 

the 2007 compliance year. These reports provide information pertaining to the number of 

RECLAIM facilities. Such a discussion would be outside of this proposed SOx RECLAIM 

amendment.

Comment #3 

WSPA understands that BARCT reassessments for the District's RECLAIM program are 

required by the California Health and Safety Code rather than by the Federal Clean Air Act. 

The discussion should clarify that advancements in control technology may or may not have 

actually occurred. Further, it is the RECLAIM program itself that dictates the timing for the 

planned reductions in emissions – a BARCT reassessment does not, by itself, impact 

implementation timing. 

Response #3 

A BARCT reassessment and the timing for this process (e.g. as expeditiously as practicable) is 

required by both the federal and California Clean Air Act, namely Section 172(c)(1) of the 

federal CAA, and Health and Safety Code (H&SC) Section 40913, 40914 and 40920.5, 

40440(b)(1), 40406, and 39616. Staff conducts a BARCT reassessment every three years which 

realign well with the frequency for amending the Air Quality Management Plan. 

Comment #4 

The relationship of the Federal Fine Particulate Implementation Rule is this current effort to 

reassess BARCT for source categories that emit SOx needs to be clearly explained. The 

District's Rule and Control Measure Forecast item that describes this RECLAIM effort refers 

only to AQMP Control Measure CMB-02, and CMB-02 is a measure to achieve a proposed 2.9 

ton per day reduction of SOx emissions. 

Response #4 

SOx is a key precursor of particulate matter (PM2.5). Reducing SOx is very important since it 

would help the Basin to meet the annual PM2.5 standard in 2014, the 24-hour PM2.5 standard in 

2010, and ready to face a potential revision of the PM2.5 standard in a near future. Other than 

mentioning the importance at reducing SOx because it is a key precursor to PM2.5, there is no 

real need to provide detailed information regarding this phenomenon. The commenter is referred 

to such documents as the Appendix V of the 2007 AQMP for more details on this subject. 

Comment #5 

The value of the target SOx reduction in the final version of CMB-02 is "2.9 tons per day" (and 

that was a change from the initial estimate of "3.0"). The regulated community needs to know, 

and fully understand, the District's goals with respect to MCS-01, and the process for potentially 

combining "facility modernization" with this current effort to reassess BARCT for RECLAIM 

sources. These issues need to be included in the Part I Staff Report. 

Response #5 

As stated in Control Measure CMB-02, the minimum target emission reductions are expected to 

be 2.9 tons per day (~ 3 tpd) from 2010 through 2014 and are expected to remain constant after 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 225 November 2, 2010 

2014. Such reduction in allocations can be across-the-board shaved or source specific 

reductions. As stated in CM CMB-02, staff may need to explore the feasibility to incorporate the 

concepts of Control Measure MCS-01 - Facility Modernization, to achieve reductions beyond 

2014. If needed, staff will discuss the concepts in Part II of the Staff Report. 

Comment #6 

It would be appropriate to include discussion and analysis of the following topics: 

• The appropriateness of using CY 2005 as a "baseline" year. 

• The methodology for calculating CY 2005 emissions since RECLAIM facilities are found in 

both calendar year and fiscal year cycles (i.e., there are both Cycle 1 and Cycle 2 facilities). 

• The 2 ton per day differential between RECLAIM SOx allocations and actual SOx emissions. 

(For example, how much was allocated to operating facilities compared to third-parties who 

do not operate facilities. This information goes to establishing an appropriate compliance 

margin, and determining how deep a hypothetical shave would cut into facility operations. 

Response #6 

Staff provides the following explanations: 

• The development process for the amended SOx RECLAIM rules started in late 2007. At that 

time, the most recent set of emission data that has been available and audited is the 2005 

emission data, therefore staff used this set of data in the analysis of the Staff Report. For 

further information, please refer to the “Annual RECLAIM Audit Reports for 2005 

Compliance Year” published in March 2, 2007. 

• Staff did not “calculate” any emissions for RECLAIM facilities. Cycle 1 and Cycle 2 

facilities are required to report emissions according to the same reporting protocol in Rule 

2012 for SOx (e.g. major SOx sources must report emissions on a daily basis and process 

SOx sources must report emissions on a quarterly basis.) Following are the reporting 

emissions group by compliance year (e.g. Emissions for compliance year 2002 means 

emissions reported from January 1, 2002 – December 31, 2002 for Cycle 1 facilities, and 

July 1, 2002 – June 31, 2003 for Cycle 2 facilities. Emissions for calendar year 2002 means 

emissions reported from January 1, 2002 – December 31, 2002 for both Cycle 1 and Cycle 2 

facilities.) 

• The 12 tons per day corresponds to allocations and also emissions reported in APEP for 

compliance year 2002 (from Jan – Dec 2002 for Cycle 1 facilities and from July 2002 – June 

2003 for Cycle 2 facilities). The 10 tons per day emissions are the emissions reported for 

2005 calendar year. The difference in 2 tpd between year 2002 & 2005 is mainly the result 

of shrinkage in SOx universe from 41 facilities since the start of the RECLAIM program to 

33 facilities in 2005 including 12 facility shutdowns, 8 inclusions and 4 exclusions is only 

about 10%. 

Comment #7 

The calculations above do not appear to be correct. Because the seven highest emitting source 

categories had CY 2005 emissions of 7.53 tons per day out of a total of 10 tons per day, their 

contribution is 75 percent (10 tons per day x 95 percent x 90 percent = 8.6 tons per day [or, 86 

percent] – but that does not agree with 7.53/10). 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 226 November 2, 2010 

Response #7 

The following values need to be part of the calculation in order to derive the correct product: 

9.92 tpd x 93.95% x 80.79% = 7.53 tpd (for the top 11 facilities) 

9.92 tpd x 95.46% x 81.09% = 7.68 tpd (for the top 12 facilities, where Saint Gobain Containers 

Inc has ceased operation). 

Comment #8 

WSPA believes that SOx allocations, which are held by entities other than RECLAM facilities, 

need to be noted and that Table EX-1 should show possibly those allocations if they are 

significant. 

Response #8 

Staff added Table A-2 in Appendix A to provide information (RECLAIM Trading Credits) that 

is held by entities other than RECLAIM facilities. 

Comment #9 

Notwithstanding staff's efforts in this regard, WSPA believes that the discussion of potentially 

applicable control technologies must be a work product of the third-party contractor study that 

the District has proposed. The discussion and analysis of control technologies should be 

included in the Part II Staff Report – not in this Part I. 

It is both premature and inappropriate to present this list of candidate potential control 

technologies as being proposed technologies. The candidate control technologies will need to be 

evaluated against the BARCT criteria, and that analysis needs to take place in Part II of the staff 

report. More appropriately, the analysis needs to occur within the scope of the potential thirdparty engineering contractor project, on which, WSPA would expect, Part II of the staff report 

will be based. 

Response #9 

There is nothing premature and inappropriate in presenting information in Table EX-2 based on 

staff’s research presented in Part I of the Staff Report. Staff views most rulemaking efforts as an 

iterative process. Staff expects that the independent work of the third party contractors will not 

result in much of a difference to the information presented in Table EX-2. However, if there is a 

difference, staff will consider the difference in the BARCT assessment process for SOx 

RECLAIM. 

Comment #10 

It is highly speculative to propose combinations of control technologies for these various sources 

because, in many cases, the technologies are essentially mutually-exclusive92. There would need 

to be a robust demonstration of the feasibility, the effectiveness, and the cost-effectiveness of 

potentially combining multiple control technologies for these source categories. 

 

92 For example, it is extremely unlikely that, due to "diminishing returns", anyone would: Combine wet scrubbing 

of FCCU flue gas with any other SOx-reduction technology, or, combine enhanced fuel gas treating for fuel gas 

combustion devices with stack scrubbing, or, combine enhanced SRU/TGU efficiency with stack scrubbing, etc. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 227 November 2, 2010 

Response #10 

Under certain situations, control technologies are mutually-exclusive. It is, however, not highly 

speculative that control technologies would be used in combination. For example, it is quite 

possible for a facility to combine wet scrubbers with SOx reducing additives. Table EX-2 

provides possible control technologies, not the proposed BARCT. In addition to the information 

provided in Part I, the BARCT analysis will be made with the results provided by the third-party 

contractors as well as additional input from the regulated community. 

Comment #11 

As noted previously, the actual target emission reduction in CMB-02 is 2.9 tons per day (not 3 

tons per day). The claim that the listed control technologies "would be employed to generate at 

least 3 tpd" suggests that the staff has already reached important conclusions regarding the 

potential BARCT reassessments and the amount of the potential reduction of SOx allocations, 

respectively. Given the facts that the proposed third-party engineering study has not yet begun, 

and that Part II of the Staff Report has not been written, all such conclusions are premature and 

inappropriate for inclusion in the Part I Staff Report. 

Response #11 

Staff conducted a first estimate of emission reductions of 2.9 tons per day shown in Control 

Measure BCM-02. A more refined estimate of emission reductions (4.7 tpd – 6.7 tpd from the 

2005 baseline inventory) was conducted during the development of Part I of Staff Report and 

was provided in the April 3 and April 30 Working Group Meetings. A subsequent estimate of 

emission reductions (6.5 tpd from the 2005 baseline inventory) were provided by the third-party 

contractors. 

Comment #12 

WSPA submits that the definition of BARCT is critical to this current effort. BARCT is not BACT 

or LAER. BARCT applies on a retrofit basis and it must consider environmental, energy and 

economic impacts. 

Response #12 

Staff agrees with the commenter. However, it should be noted that it is not unusual in which the 

levels of BARCT are equal to the levels for BACT (or LAER), especially for add-on control 

devices such as wet/dry scrubbers. In some situations (e.g. PAR 1146 and 1146.1), the BARCT 

level for certain categories of equipment may be more stringent than the corresponding BACT 

level. The primary reason for this difference was that the BACT assessment has not been 

conducted for 8 years, not taking into recent advancements on control technologies. In addition, 

BARCT may anticipate future technological development. 

Comment #13A 

Although WSPA recognizes the precursor relationship between SOx emissions and ambient PM 

2.5, as a practical matter, the discussion in the following section is confusing – largely because 

it fails to establish a clear and understandable relationship between PM and this effort 

regarding the RECLAIM SOx program. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 228 November 2, 2010 

Comment #13B 

First, the two statements in the preceding paragraph, taken together, are not clear. Second, the 

statistic regarding the exposure of Southern California residents to PM 2.5 needs to be 

substantiated. For example, there needs to be some discussion regarding the nation-wide 

monitoring for PM 2.5, etc. (if PM monitoring data for the rest of the nation is sparse, then PM 

monitoring in a densely populated area such as Southern California would skew the result). 

Comment #13C 

Without establishing the basis, the discussion in the paragraph above is seemingly unrelated to 

SOx RECLAIM. 

Response #13A-13C 

Please refer to the 2007 AQMP and specifically Appendix 5, for further explanations. 

Comment #14 

WSPA is concerned that the discussion in the paragraph above implies that the District intends 

to use RACM and RACT as two barometers for evaluating potential SOx reduction technologies 

rather than using BARCT, as discussed earlier in the staff report. 

As stated previously, the preliminary draft Part I report has not established a basis for linking 

SOx reductions to improvements in PM air quality. The discussion regarding the effectiveness of 

controlling SOx and/or NOx for PM air quality improvement needs to be substantiated. 

Response #14 

RACM and RACT call out for a minimum level of control required by the U.S. EPA in their 

Clean Air Fine Particle Implementation Rule. The District is required to establish BARCT for 

this proposed SOx RECLAIM rule amendment as discussed earlier in the Staff Report. BARCT 

would more likely be more stringent than the levels presented in RACM/RACT. 

This Staff Report incorporates other documents which establish a basis for linking SOx 

reductions to improvements in PM air quality as part of the rule making documents. This 

linkage is well documented and substantiated in other public documents such as the 2007 

AQMP, and documents that were used as the basis to develop the Clean Air Fine Particle 

Implementation Rule. 

Comment #15 

WSPA suggests that the staff report should list the SOx facilities that have exited RECLAIM, and 

should indicate the reason for their leaving the program (and, if due to plant closure, did the 

business claim that the decision to close was in any way related environmental regulations, or, 

the RECLAIM program in particular). 

Response #15 

Please refer to the District’s annual RECLAIM audit reports published annually in March for this 

information. Typically plant closure is the result of several factors. Staff believes that 

discussions on plant closures, or facilities opt-in into SOx RECLAIM is better placed in the 

RECLAIM annual audit reports. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 229 November 2, 2010 

Comment #16 

The first two sentences are unclear (e.g., were the decreasing allocations based on BARCT that 

was initially in place or, that would likely be implemented in the future?). 

The statement assumes that advancements in control technology are occurring constantly but, as 

a practical matter, that is not the case. The sentence should read, “capture any advancement 

...". 

The concept of declining emissions allocations, which were a basic design element of the 

RECLAIM program, already incorporate the goal of expeditious emissions reductions. The 

sentence could report a more accurate number – the actual reduction was 22.5 percent. 

Response #16 

The decreasing allocations were based on, in part, the levels of BARCT that would be 

implemented as expeditiously as possible in the future. 

Staff did not intend to imply the control technologies are “constantly” being improved. Rather 

staff is alerted at technology advancements, or retrospectively leads back to ascertain if control 

technology improvements warranted a BARTC assessment. Either approaches recognized 

progress made by the regulated industry, vendors and contractors in control technology 

advancements. 

The concept of declining emission allocations indeed incorporates expeditious emission 

reductions. The facility allocations since 2003 remain constant based on a BARCT assessment 

in 1993. A BARCT re-assessment today will in all likelihood establish further declines in SOx 

emission allocations in order to reach PM2.5 attainment in 2015. 

Since its initial rule making effort, there have been several amendments to the RECLAIM rules. 

In January 2005, a BARCT analysis was re-conducted for NOx, and as a result of this analysis, 

the RECLAIM rules were amended and the NOx annual allocations previously given to the NOx 

RECLAIM facility were further reduced by approximately 20% to reflect BARCT. 

Comment #17 

WSPA recalls that the 2003 allocations included an extra "shave". Tier 1 represented BARCT at 

the time; Tier 2 was an additional 34 percent shave 

The BARCT analysis for SOx is being re-evaluated through the current staff effort. It would be 

more correct to state that an amendment is (or, will be) based on the BARCT reassessment. 

Response #17 

A BARCT assessment in 1993 established the declining Tier 1 and Tier 2 allocations. BARCT 

is undergoing a reevaluation in this Staff Report and will in all likelihood set another reduction 

for SOx allocations. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 230 November 2, 2010 

Comment #18 

WSPA strongly believes that, as was the case for the RECLAIM NOx program shave, any SOx 

shave must apply to the universe of RECLAIM SOx facilities. 

Although the estimated SOx reductions in the AQMP control measure are accurately stated, the 

AQMP control measure did not contain any documentation regarding the basis for the numbers. 

Because it is not possible to verify, or even comment on, the reasonableness of the estimates, 

they must not become benchmarks for evaluating the potential outcome of the BARCT 

reassessment and SOx-shave. 

As previously stated, there needs to be an explanation of the process for evaluating the possible 

secondary goal of including MCS-01 with this BARCT reassessment. WSPA is concerned that 

potentially combining two the goals will make it difficult to conduct their respective analyses. 

Response #18 

The paragraph written in Section 1.4 correctly stated the information presented in the Control 

Measure CMB-02. 

Staff first conducted an analysis for emission reductions in 2006 during the development of 

Control Measure CMB-02 which resulted in a minimum of 2.9 tpd (approximately 3 tpd) 

emission reductions. Staff conducted a follow-up analysis in April 2008, resulting in a range of 

emission reductions from 4.7 tpd – 6.7 tpd from the 2005 emissions baseline. This range was 

presented in the April 3 and April 30 Working Group Meetings. Expert contractors conduct a 

third independent analysis of emission reductions and cost effectiveness in September 2008 to 

assist staff in making its final determination of BARCT. They estimated about 6.5 tpd emission 

reductions from the 2005 emissions baseline. The final results of potential RTC reductions and 

how the reduction would be distributed to maintain the integrity, equity and characteristics of 

the RECLAIM program will be discussed in Part III of the Staff Report. If needed to achieve 

addition emission reductions for 2014, staff will incorporate the concepts of Control Measure 

MCS-01 as stated in CM CMB-02, and will discuss the process in Part III of the Staff Report. 

Comment #19 

In view of the potential review of BARCT to be conducted by an engineering contractor, the 

staff's recent effort can only be regarded as preliminary. Further there is an important 

distinction between identifying technologies that might be applicable to a particular source 

category, and making an assessment that any technology or combination of technologies 

represents BARCT. 

Response #19 

Staff has conducted an extensive engineering research to identify the control technologies and 

assess the possible potential emission reductions that can be achieved. The third party 

contractors will conduct their own engineering assessment on control technologies, and cost 

estimates to assist staff in making the final decision on BARCT and emission reductions. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 231 November 2, 2010 

Comment #20 

It is premature to state that the SOx reductions technologies, which are described in the staff 

report, are "applicable" – those determinations have not yet been made, and can only be made at 

the conclusion of the proposed engineering contractor study. 

Reports of installed costs and resultant cost-effectiveness, as reported in the "literature", are 

usually for uncontrolled sources. The reports are rarely applicable to sources that are already 

well-controlled, as is the case for facilities in the South Coast Basin. 

Generally speaking, reliance on cost or cost-effectiveness values from "the literature" would be 

a serious mistake. In many cases the District has access to information regarding the actual 

costs of installations at local refineries. In other cases, site-specific engineering estimates need 

to be made because this entire BARCT reassessment exercise has to focus on potential retrofit 

installations.

Response #20 

As pointed out in previous responses, the technical feasibility and cost analysis is developed over 

the entire rule making process. Relying upon data from literature is acceptable in the earlier 

stage of the rule development process. 

Comment #21 

WSPA notes that, in the absence of specific documentation regarding the reason that a facility 

installs emissions control equipment, it cannot be assumed that such installations have been 

determined to be cost effective. Many installations of emission control equipment have nothing 

whatsoever to do with cost-effectiveness considerations – rather, they might be part of 

negotiated Consent Decrees, they might be based on need to provide emissions offsets, etc. 

Where any determinations regarding cost-effectiveness might have been made, and when those 

determinations are quoted in the Staff Report, they need to be documented. 

It is premature to suggest any definitive conclusions with respect to the amount of SOx emission 

reductions that might be expected. If various control technologies are ultimately determined to 

be feasible and cost effective, then the resulting reductions will be used in calculating the 

specific amount of the allocation shave for SOx RECLAIM sources. 

Response #21 

In CM CMB-02, staff estimated a range cost effectiveness from $10,000 - $16,000 per ton SOx 

reduced. The third party contractors will assist staff in conducting detailed cost estimates for this 

rule amendment and the results will be presented in Part II of the Staff Report. 

Comment #22 

The discussion in the preceding paragraph should reflect the proposed engineering contractor 

study. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 232 November 2, 2010 

Response #22 

Staff will revise the Preliminary Draft Staff report accordingly when new information surfaces. 

The third party contractors’ analyses will be summarized and presented in Part II of the Staff 

Report. 

Comment #23 

WSPA believes that the 12 ton per day value represents SOx allocations, not actual emissions. 

We also note that not all of the allocations are held by RECLAIM facilities (some allocations are 

held by third-party investors, etc.). WSPA cautions that care needs to be taken to distinguish 

between SOx allocations and actual emissions. 

It is also important to show the SOx allocations held by facilities compared to those held by 

investors for both current and future years because the amount of allocations held by investors 

will increase proportionally in 2012 (compared to 2008) while the amount held by facilities will 

decrease.

Response #23 

As shown in Table 3-4 of the “Annual RECLAIM Audit Report for the 2002 Compliance Year”, 

dated March 5, 2004, the actual emissions for compliance year 2002 was 4,374 tons (12 tpd). 

The total RTCs (allocations and converted ERCs) were reported to be 4,924 tons (13 tpd). 

The RTCs held by investors and by facilities may change on a daily basis. As of March 11, 

2009, the RTCs held by the investors were 295 tons for compliance year 2009, 207.5 tons for 

compliance year 2010 (a decrease compared to year 2009), and 339.9 tons for 2011 and beyond. 

Comment #24

Because Table 2-1 makes a comparison between the RECLAIM NOx and SOx programs, 

respectively, it is important to note the following: 

• The NOx shave applied equally to all facilities in the RECLAIM NOx universe. 

• The NOx shave recognized the need for, and included, a compliance margin. 

These two characteristics of the NOx shave must also apply to the present consideration of a 

SOx shave. 

Although the data show that, with respect to SOx, RECLAIM facilities represent a greater 

portion of the emissions inventory, they do not by themselves support a claim of any unusual 

importance for the current BARCT reassessment exercise for SOx. As stated above, WSPA 

believes that the 12 ton per day number represents allocations not emissions. 

Response #24 

In the NOx universe, 87% of the total emissions (24.02 tpd out of 27.61 tpd for compliance year 

2003) are generated from the top 16% (54 out of 346 facilities) of the facilities. Yet the NOx 

shave is divided equally (by percentage) across the NOx universe. Therefore, similarly in the 

SOx universe, even though 95% of the total emissions (9.47 tpd out of 9.92 tpd) is generated 

from the top 12 facilities out of 33, the SOx RTC reductions will probably be divided equally (by 

percentage) across the SOx universe. As indicated in Control Measure CMB-02, however, the 

shave may be divided equally to 33 facilities, or may be restricted to specific facilities. As 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 233 November 2, 2010 

indicated in Part III of the Draft Staff Report, additional analyses will be conducted to provide 

more information on how the RTC reductions should be executed to maintain the integrity and 

operational of the SOx RECLAIM program. 

See Response #3 regarding the requirement of BARCT reassessment. The 12 tpd is actual 

emissions in compliance year 2002. 

Comment #25 

Projected emissions for future years 2014 and 2023 are speculative at best. The staff report 

should indicate whether or not future year emission projections include the effect of allocation 

shaves. The precursor relationship of SOx to ambient PM should not simply be described as a 

"given" because there is no foundation for this claim in the staff report. 

Response #25 

The future estimated emissions for 2014 and 2023 (11.7 tpd and 11.8 tpd, respectively, without 

allocation shaves; and 8.8 tpd and 8.9 tpd, respectively, with allocation shaves) are clearly shown 

in CM CMB-02. The foundation and explanation for a relationship between SOx emissions and 

ambient PM can be found in Appendix 5 of the 2007 AQMP. 

Comment #26 

WSPA is not aware of any refineries in the South Coast basin that are not in the RECLAIM 

program. The staff report should clarify this issue. 

Response #26 

For clarification, the wording “Non-RECLAIM Refineries” are changed to “Non-RECLAIM 

Sources”. In 2002, the refineries reported 6.9 tpd SOx emissions for flares and upset conditions. 

Flares and upset conditions were not counted in “RECLAIM Sources”, which was ranked #2 in 

Table 2-2. 

Comment #27 

The language in the staff report consistently (and, perhaps, misleadingly) suggests that a 3 ton 

per day (the correct value is 2.9 tons per day) reduction in SOx allocations is a virtual certainty. 

It is not – primarily because the origin of the 2.9 ton per day goal has not been substantiated. 

The purpose of the BARCT reassessment is to determine the level of the SOx allocations 

reduction, if any, that is appropriate and can justified on the basis of available retrofit 

technology, cost effectiveness, etc. Further, it should be noted that other source categories in 

Table 2-2 might be reasonable candidates for SOx emissions reductions. 

Response #27 

As shown in the 2007 AQMP (Table 3-8 of Chapter 3 of the 2007 AQMP), RECLAIM sources 

were ranked #2 in SOx emissions in 2002, and were expected to rank #2 in 2014 and 2023. 

Among other stationary sources, RECLAIM sources have the highest possibility to achieve 3 

tons per day reductions in 2014 cost effectively, substantiated by staff’s analysis in CM CMB-02 

and the analysis in Part I of Staff Report. The cost effectiveness ranking of all stationary source 

control measures in the 2007 AQMP is shown in Table 6-5. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 234 November 2, 2010 

Comment #28 

As noted previously, the staff report should address the significance of using CY 2005 as a 

reference: 

• What is the significance of CY 2005? 

• Is CY 2005 a representative year? (Some analysis and discussion is needed.) 

There needs to be some discussion regarding why the analysis was cut off at twelve facilities. 

There needs to be some discussion of the reason for, and implication of, including a facility that 

is shut down in this analysis. 

Response #28 

Please refer to Response #6. 

Comment #29 

The derivation of the claimed 80 percent value needs to be presented. (See the comments 

regarding Table EX-1.) 

Response #29 

Please refer to Response #7. 

Comment #30 

There needs to be some demonstration regarding the selection of 2005 as the baseline year. 

Response #30 

As presented in the April 3 Working Group Meeting (slide #4), the 2005 emissions were selected 

to be used in this rule amendment because they are within the range of emissions from other 

current years. The emissions from these top emitting categories of equipment were reported to 

be 7.5 tpd for 2005, 7.9 tpd for 2006, and 7.3 tpd for 2007. Staff also will estimate RTC 

reductions using other baseline year (1997) as shown in the 2005 NOx RECLAIM amendment. 

Comment #31 

There should be some discussion regarding the characterization of a source as "major", and it 

should be noted that this description has a specific meaning within the context of Regulation XX. 

Response #31 

The definition for major SOx source is in Rule 2011 (c). 

Comment #32 

It should be noted that many of the FCCUs at refineries in the South Coast basin are also 

equipped with expander turbines, which are used to recovery energy from the flue gas leaving 

the regenerator. An expander turbine, and its associated third-stage separator (used to reduce 

filterable PM in the FCCU flue gas stream entering the turbine) are additional elements in the 

flue gas train, which collectively complicate the task of maintaining the required pressure 

balance within the FCCU. 

Response #32 

Staff acknowledges this component of the FCCU operation. However, Figure 3-1 is a generic 

flow diagram that was never intended to show every single piece of equipment included in the 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 235 November 2, 2010 

FCCU at each refinery. Any components which would complicate the reductions of SOx 

emissions should be captured in the third party consultants’ analysis. 

Comment #33 

An electrostatic precipitator and an SCR unit (where one is employed) occupy considerable 

refinery plot space, and limit the potential use of other systems such as wet gas scrubbers.

The title of the Figure should be "Typical Fluid Catalytic Cracking Unit". A block representing 

expander turbines should be added because these are common. The block representing SCR 

should be deleted or labeled as "Optional", because SCRs are uncommon. 

Response #33 

See Responses #32. 

Comment #34 

RECLAIM allocations were not issued to process units or individual pieces of equipment but, 

rather, to the facility as a whole. 

Response #34 

RECLAIM allocations were issued to the facility as a whole. However, total facility allocations 

were estimated for each SOx source at the facility according to the methodology described in 

Rule 2002. 

Comment #35 

The average value for the three years, 2005, 2006 and 2007 is 3.33 tons per day. There should 

be an explanation regarding why the highest year was used. Further, there needs to be an 

analysis regarding the impact of FCCU turnarounds, if any, on the mass emission estimates. 

(Also see comment for Table 3-2 below.) 

Response #35 

Staff started the development of this SOx RECLAIM amendment in November of 2007. The 

most recent set of RECLAIM emissions audited at that time was the 2005 emissions (Ref: 

Annual RECLAIM Audit Report for 2005 Compliance Year, March 2, 2007). Staff will provide 

two sets of estimation: 1) “real” emission reductions expected from the 2005 actual emissions 

baseline; and 2) RTC reductions based on the 1997 and the 2005 actual emission baselines. (The 

RTC reductions estimated from the 1997 baseline will be conducted as suggested by the refinery 

task force in several meetings with the District following the methodology outlined in the 

analysis for the 2005 NOx RECLAIM amendment.) 

Comment #36 

The statement regarding the lack of specific SOx concentration or mass limits for FCCUs is not 

correct. FCCUs can be subject to Federal New Source Performance Standards, provisions of 

Consent Decrees, etc. 

As noted above, RECLAIM SOx allocations are provided to the facility not to a process unit 

(e.g., an FCCU). The amount of a facility's SOx allocations have been steadily declining since 

they were first granted at the start of the RECLAIM program. 
Final Staff Report – Part 1 Chapter 14 – Comments & Responses 

_____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 236 November 2, 2010 

Commercial availability is only one issue that needs to be considered when evaluating BARCT – 

other considerations are environmental, energy and economic impacts. 

 

WSPA is not aware of any basis for the statement implying a hypothetical increase in capacity, 

and a corresponding need to upgrade any control device. The statement is unsubstantiated and 

should be deleted. 

Response #36 

The statement regarding the lack of specific SOx concentration or mass limits for FCCUs was 

meant for AQMD RECLAIM regulations, not EPA regulations. 

The facility’s SOx allocations are the summation of all allocations estimated for each SOx 

source/process category at the refinery. The facility's SOx allocations were steadily declining 

since 1993 to 2003, and remaining constant after 2003. 

In the analysis of BARCT, staff will include only commercial availability technologies but not 

the technologies in development or at the research phase, and will evaluate BARCT considering 

environmental, energy and economic impacts as governed by federal/state rules. 

The commenter may not be aware of any increase in FCCU capacity since it is confidential 

information. 

Comment #37 

WSPA submits that it is unlikely that each refinery had the same FCCU SOx emissions factor. 

That does not seem reasonable. We wonder if 13.7 lbs/1000 bbls might have been the Tier 1 

shave target, not what was actually being emitted in the so-called peak years? 

Response #37 

The 13.7 lbs/1000 bbls is the emission factor used to calculate Tier I emissions for FCCUs.
Final Staff Report References 

____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 237 November 2, 2010 

References 

AQMD, 2007. South Coast Air Quality Management District – 2007 Air Quality Management 

Plan, June 2007. 

AQMD, 2006. RECLAIM 2005 Annual Permit Emissions Report, March 2006. 

AQMD, 2007. Facility Permit to Operate of BP West Coast Products LLC, BP Wilmington, 

Draft, Facility ID 131249. September 25, 2007. 

AQMD, 2007. Addendum to the August 2006 Final Environmental Impact Report for the 

Chevron Heavy Crude Project, certified May 2, 2007. 

AQMD, 2003. Rule 1105.1 and Staff Report – Reduction of PM10 and NH3 from Fluid 

Catalytic Cracking Units, November 3, 2003. 

BP, 2001. BP Exploration & Oil Company, Amoco Oil Company, and Atlantic Richfield 

Company - Consent Decree, Civil Case No. 2:96CV095RL, 2001. 

BP, 2005. BP Texas City Site – Texas City, Texas – 2004 Environmental Statement, June 2005. 

BP, 2007. BP Coke, 2007, http://coke.bp.com/tech/tech.cfm. 

BUTLER, 2006. Reducing Refinery SOx Emissions. E. Butler, K. Groves, J. Hymanyk of 

Chevron Canada Limited and M. Maholland, P. Clark, and G. Aru of Intercat Inc. Petroleum 

Technical Quarterly, Quarter 3, 2006. 

CARB, 1978. Feasibility of Installing Sulfur Dioxide Scrubbers on Stationary Sources in the 

South Coast Air Basin of California. Prepared by P.P. Leo and J. Rossoff of The Aerospace 

Corporation for California Air Resources Board, Contract No. A6-211-30, August 1978. 

http://www.arb.ca.gov/research/abstract/a6-211-30.htm

DWR, 2010. The 2009 California Water Plan Update. 

EAGLESON, 2005. A Logical and Cost Effective Approach for Reducing Refinery FCCU 

Emissions. S.T. Eagleson, G. Billemeyer, N. Confuorto, and E. H. Weaver of BELCO 

Technologies Corporation, and S. Singhania and N. Singhania of Singhania Technical Services 

Pvt., India, Presented at PETROTECH 6th International Petroleum Conference in India, January 

2005 

ENVIRONMENTAL PROGRESS, 2001. Eliminating a Sulfuric Acid Mist Plume from a Wet 

Caustic Scrubber on a Petroleum Coke Calciner, Charles Brown and Paul Hohne of VECO 

Pacific Inc., Environmental Progress, Vol. 20, No. 3, October 2001. 

EPA, 1983. Estimation of the Importance of Condensed Particulate Matter to Ambient 

Particulate Levels, U.S. EPA, NTIS PB84102565, April 1983. 
Final Staff Report References 

____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 238 November 2, 2010 

EPA, 2007. The U.S. Environmental Protection Agency RACT/BACT/LAER Clearinghouse, 

2007. http://cfpub.epa.gov/rblc

EQUILON, 2001. Motiva Enterprises LLC, Equilon Enterprises LLC, and Deer Park Refining 

Limited Partnership Civil Judicial Settlement, March 21, 2001. 

GRACE Davidson, 2000. Super DESOx ® - Providing Benchmark Effectiveness for SOx 

Reduction, Dudley Sellery of Murphy Oil Corporation and Bob Riley of GRACE Davidson. 

HORN, 1984. Performance of Dry Flue Gas Desulfurization on a Petroleum Coke Kiln 

Application, R.J. Horn of Ecolaire Environmental Company and J.F. Bent of Martin Marietta 

Aluminum, Journal of the Air Pollution Control Association, September 1984. 

INTERCAT, 2002A. Intercat SOXGETTER - SOx Reduction Additive Technology Overview, 

March 27, 2002 

INTERCAT, 2002B. Ultra Lo-SOx – SOx Emission Control Agent. www.intercatinc.com

LADCO, 2005. Best Available Retrofit Technology (BARCT) for Selected Non-Electric 

Generating Units (EGU) Source Categories, MACTEC Federal Programs, Inc. developed for 

Lake Michigan Air Directors Consortium (LADCO), June 28, 2005. 

LADWP, 2005. The 2005 Urban Water Management Plan of the Los Angeles Department of 

Water and Power. 

LINERO, 2006. What’s Up with Cement Plant Permitting?, A.A. Linero, Florida Department of 

Environmental Potection, 2006. 

MARAMA, 2007. Assessment of Control Options for Petroleum Refineries in the Mid-Atlantic 

Region – Final Technical Support Document. Prepared by MACTEC Federal Programs, Inc. for 

the Mid-Atlantic Regional Air Management Association (MARAMA), January 31, 2007. 

MASSIE, 2005. Catalysts for Lower Temperature Tail Gas Unit Operation. S. Massie and C. 

Wilson of Criterion Catalysts & Technologies, presented at the Brimstone Sulfur Recovery 

Symposium, Vail, Colorado, September 2005. 

MEYER, 2006. Improving Sulfur Recovery Units, S.F. Myer and C. Kulczycki of MECS, E. 

Juno of Sinclair Oil Corporation, and N. Watts of CEntry Constructors and Engineers, Petroleum 

Technical Quarterly, Quarter 3 of 2006. 

NESCAUM, 2005. Assessment of Control Technology Options for BART-Eligible Sources – 

Steam Electric Boilers, Industrial Boilers, Cement Plants, and Paper and Pulp Facilities. 

Northeast States for Coordinated Air Use Management (NESCAUM) in partnership with the 

Mid-Atlantic Northeast Visibility Union (MANE-VU), March 2005. 
Final Staff Report References 

____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 239 November 2, 2010 

NESCAUM, 2007, Five-Factor Analysis of BARCT Eligible Sources – Survey of Options for 

Conducting BART Determinations. Prepared by Northeast States for Coordinated Air Use 

Management (NESCAUM) for the Mid-Atlantic Northeast Visibility Union (MANE-VU), June 

1, 2007. 

NWCAA, 2006. BP West Coast Products, LLC. Cherry Point Refinery Blaine, Washington, Air 

Operating Permit, Final Modification. Northwest Clean Air Agency, September 06, 2006. 

PECHAN, 2005. Update of Control Equipment Data to Support Minnesota Pollution Control 

Agency (MPCA) Control Equipment Rule – Final Report, Stephen M. Roe, Ying K. Hsu, Maggie 

Ma, Holly C. Linquist, E.H. Pechan & Associates, Inc., Report No. 05.06.00X/9446.000 CFMS 

No. A72995, June 2005. 

PUGET, 2007. Saint-Gobain Containers Glass Melting Furnaces. E-mail from Gerry Pade, 

Engineer of Puget Sound Clean Air Agency to Minh Pham, Air Quality Specialist of SCAQMD, 

November 30, 2007. 

TRIMER, 2007. Treatment for Fine Particles and Gas Cloud Chamber® Technology and Its 

Applications. K. Moss and R. Gravley, 2007. 

VIERHEILIG, 2003. The Role of Additives in Reducing Fluid Catalytic Cracking SOx and NOx 

Emissions, Vierheilig, A. and Evans, M., Petroleum and Coal, Volume 45, 3-4, 147-153, 2003. 

WEAVER, 2006. Evaluating Wet Scrubbers, Edwin H. Weaver with BELCO Technologies 

Corporation, Petroleum Technology Quarterly, Quarter 3, 2006. 

WEST BASIN, 2008. West Basin Municipal Water District Strategic Business Plan, January 

2008. http://www.westbasin.org/files/pdf/FINAL%20Strategic%20Business%20Plan%201-28-

2008.pdf

WEST BASIN, 2005. West Basin Municipal Water District - 2005 Urban Water Management 

Plan http://www.westbasin.org/files/pdf/UWMP_2005.pdf

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WORLEYPARSONS, 2006. Sulfur Technology, Capability and Experience. WorleyParson. 
Final Staff Report – Part 1 Appendix A – 2005 SOx RECLAIM Emissions

____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 240 November 2, 2010 

Appendix A – Emissions, RTC Holdings, and Initial 

Allocations 

TABLE A-1 

2005 SOx Emissions at SOx RECLAIM Facilities 

Facility ID Facility Name Cycle

Emissions 

(tons per 

year)

Emissions 

(tons per day)

Cumulative 

Percentage

131003 BP WEST COAST PROD.LLC BP CARSON REFINERY 2 679.4 1.86 0.19

800363 CONOCOPHILLIPS COMPANY 2 421.2 1.15 0.3

114801 RHODIA INC. 1 410.7 1.13 0.42

800370 EQUILON ENTER., LLC, SHELL OIL PROD. U S 1 363.6 1 0.52

800030 CHEVRON PRODUCTS CO. 2 362.5 0.99 0.62

800089 EXXONMOBIL OIL CORPORATION 1 333.5 0.91 0.71

800026 ULTRAMAR INC 1 312.8 0.86 0.8

800362 CONOCOPHILLIPS COMPANY 1 210.7 0.58 0.85

131249 BP WEST COAST PRODUCTS LLC,BP WILMINGTON 1 130.1 0.36 0.89

800181 CALIFORNIA PORTLAND CEMENT CO 2 100.5 0.28 0.92

7427 OWENS-BROCKWAY GLASS CONTAINER INC 1 74.7 0.2 0.94

108701 SAINT-GOBAIN CONTAINERS, INC. 1 55.9 0.15 0.95

8547 QUEMETCO INC 1 37.3 0.1 0.96

124838 EXIDE TECHNOLOGIES 1 36.9 0.1 0.97

117247 EQUILON ENTERPRISES, LLC 1 31.2 0.09 0.98

800183 PARAMOUNT PETR CORP 1 22.6 0.06 0.99

35302 OWENS CORNING ROOFING AND ASPHALT, LLC 2 7.6 0.02 0.99

800264 EDGINGTON OIL COMPANY 2 6.7 0.02 0.99

115389 AES HUNTINGTON BEACH, LLC 2 6.4 0.02 1

40196 GUARDIAN INDUSTRIES CORP. 2 6.1 0.02 1

16642 ANHEUSER-BUSCH INC., LA BREWERY 1 5.4 0.01 1

42775 WEST NEWPORT OIL CO 1 2.3 0.01 1

119104 CALMAT CO 1 1.1 0 1

800182 RIVERSIDE CEMENT CO 1 0.7 0 1

21887 KIMBERLY-CLARK WORLDWIDE INC.-FULT. MILL 2 0.4 0 1

45746 PABCO BLDG PRODUCTS LLC,PABCO PAPER, DBA 2 0.1 0 1

800372 EQUILON ENTER. LLC, SHELL OIL PROD. US 2 0.1 0 1

Total 3621 9.92

(Note: There are 27 facilities out of total 33 facilities listed in this table. The remaining four facilities reported zero 

emissions in 2005.) 

Total 2005 reported emissions = 9.92 tons per day 

Total 2005 audited emissions = 10.04 tons per day
Final Staff Report – Part 1 Appendix A – 2005 SOx RECLAIM Emissions

____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 241 November 2, 2010 

TABLE A-2 

RTC Holdings and Initial Allocations for Compliance Year 2012 As Of August 29, 2009 

11 Major Facilities 

 Count 

Facility 

ID Facility Name 

RTC 

Holdings 

(tpd) 

Initial 

Alloc (tpd) 

CY2012 Int12alloc 

1 131003 BP WEST COAST PROD.LLC BP CARSON REF. 1.47 0.86 

2 800030 CHEVRON PRODUCTS CO. 1.21 0.86 

3 800362 CONOCOPHILLIPS COMPANY 0.59 0.21 

4 800363 CONOCOPHILLIPS COMPANY 1.38 0.78 

5 800089 EXXONMOBIL OIL CORPORATION 1.15 0.50 

6 800026 ULTRAMAR INC (NSR USE ONLY) 0.72 0.57 

7 800436 TESORO REFINING AND MARKETING CO 1.20 0.52 

8 131249 BP WEST COAST PRODUCTS LLC,BP WILMINGTON 0.84 0.84 

9 800181 CALIFORNIA PORTLAND CEMENT CO (NSR USE) 0.27 0.22 

10 7427 OWENS-BROCKWAY GLASS CONTAINER INC 0.31 0.68 

11 114801 RHODIA INC. 1.07 1.12 

 TOTAL 10.21 7.16 

 

21 Remaining Facilities 

12 115389 AES HUNTINGTON BEACH, LLC 0.02 0.01 

13 148236 AIR LIQUIDE LARGE INDUSTRIES U.S., LP 0.00 

14 16642 ANHEUSER-BUSCH INC., (LA BREWERY) 0.02 0.02 

15 119104 CALMAT CO 0.00 

17 800264 EDGINGTON OIL COMPANY 0.02 0.02 

18 800372 EQUILON ENTER. LLC, SHELL OIL PROD. US 0.00 1.04 

19 124838 EXIDE TECHNOLOGIES 0.14 0.14 

20 124808 INEOS POLYPROPYLENE LLC 0.00 

21 21887 KIMBERLY-CLARK WORLDWIDE INC.-FULT. MILL 0.00 0.00 

22 800080 LUNDAY-THAGARD COMPANY 0.00 0.00 

23 35302 OWENS CORNING ROOFING AND ASPHALT, LLC 0.03 0.03 

24 45746 PABCO BLDG PRODUCTS LLC,PABCO PAPER, DBA 0.02 0.02 

25 800183 PARAMOUNT PETR CORP (EIS USE) 0.13 0.11 

26 8547 QUEMETCO INC 0.14 0.14 

27 800182 RIVERSIDE CEMENT CO (EIS USE) 0.06 0.12 

28 14944 TECHALLOY CO., INC. 0.01 0.01 

29 151798 TESORO REFINING AND MARKETING CO 0.08 0.06 

31 12185 US GYPSUM CO 0.01 0.01 

32 42775 WEST NEWPORT OIL CO 0.03 0.86 

 TOTAL 0.73 2.60 

*CENCO & P.Q.CORP have Zero RTC Holdings 

 
Final Staff Report – Part 1 Appendix A – 2005 SOx RECLAIM Emissions

____________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 242 November 2, 2010 

TABLE A-2 (Cont.) 

Inactive Facilities 

33 40196 GUARDIAN INDUSTRIES CORP. 0.00 0.10 

34 99588 DOMTAR GYPSUM INC 0.01 0.01 

37 106797 SAINT-GOBAIN CONTAINERS, INC. 0.00 

38 108701 SAINT-GOBAIN CONTAINERS, INC. 0.00 

39 117247 EQUILON ENTERPRISES, LLC 0.00 

51 800184 GOLDEN WEST REF CO 0.00 0.21 

52 800223 TEXACO REF & MARKETING INC 0.00 

 TOTAL 0.01 0.32 

 

Investors 

35 101337 NATIONAL OFFSETS 0.00 

36 104017 AERA ENERGY LLC 0.03 

40 139796 CITY OF RIVERSIDE PUBLIC UTILITIES DEPT 0.02 

41 140540 CALIFORNIA LNG PROJECT CORPORATION 0.00 

42 152857 GEORGIA-PACIFIC GYPSUM LLC 0.00 

43 700004 CANTOR FITZGERALD BROKERAGE, L.P. 0.00 

44 700058 U S TRUST COMPANY, NATIONAL ASSOCIATION 0.00 

45 700062 BRIAN ANDERSON 0.14 

46 700122 GREY K ENVIRONMENTAL FUND, L.P. 0.49 

47 700123 APEX PLASTICS & TOOLING, INC. 0.00 

48 700128 GREY K FUND LP 0.00 

49 700144 OLDUVAI GORGE, LLC 0.15 

50 700153 TAUBER OIL COMPANY 0.00 

 TOTAL 0.83 

 

Total for active RECLAIM facilities 11.77 10.08 
Final Staff Report – Part I Appendix A – 2005 S

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 243 

TABLE A-3 

RTCs Available for RECLAIM Market from Shutdown Facilities 

Facility 

ID Name 

Shutdown 

Compliance 

Year 

Initial 

Allocations 

2010+ 

2010+ 

Holding as 

of 8/26/2010

IYB RTC 

Available 

Market 

(lbs) 

6281 

US GOVT,MARINE CORPS AIR STATION,EL TORO 2000 1,892 0 1,892 

6394 ANAHEIM FOUNDRY INC 1996 7,782 0 7,782 9141 CANNERS STEAM CO INC 2007 8,596 0 8,596 

12912 LIBBEY GLASS INC 2004 71,816 0 71,816 18984 ANCHOR GLASS CONTAINER CORP 1994 136,016 0 136,016 40196 GUARDIAN INDUSTRIES CORP. 2007 71,882 0 71,882 60942 

GAF BUILDING MATERIALS CORPORATION 1994 70,052 0 70,052 

67945 GREAT WESTERN MALTING CO., INC. 2002 125,326 0 125,326 79397 

OWENS-BROCKWAY GLASS CONTAINER INC 1996 102,445 0 102,445 

99588 DOMTAR GYPSUM INC 1999 8,572 8,572 0 

106797 SAINT-GOBAIN CONTAINERS, INC. 2004 235,558 0 235,558 108701 SAINT-GOBAIN CONTAINERS, INC. 2007 0 0 0 800047 FLETCHER OIL & REF CO 2000 42,094 0 42,094 800184 GOLDEN WEST REF CO 2001 150,557 243 150,314 800232 HUNT-WESSON INC 1996 9,564 0 9,564 

Total from shutdown facilities (tons per day

 From Glass Facilities (tp
Final Staff Report – Part I Appendix A – 2005 S

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 244 

TABLE A-4 

2005 SOx Emissions of Top Seven Groups of Equipment 

Group Fac Name Description Fuel Type 2005 Emissions (lbs) 

1 B REGENERATOR, FCCU 755399.17 1 F REGENERATOR, FCCU 447175.34 

1 A REGENERATOR 281211.84 1 D REGENERATOR 195964.32 

1 D BOILER 30445.34 

1 C REGENERATOR 703085.36 

1 E REGENERATOR, FCCU 0 

1 E BOILER, CO WASTE HEAT, FCCU 181757.45 

 Total for 6 FCCUs 

2 B HEATER, CRUDE OIL DISTILLATION REF_GAS 57649.9 2 D BOILER REF_GAS 25516.55 

2 D HEATER REF_GAS 47760.79 

2 D FURNACE REF_GAS 32123.51 

2 C HEATER REF_GAS 76489.74 

2 C HEATER REF_GAS 64590.83 

2 C BOILER REF_GAS 45844.81 

2 C BOILER REF_GAS 43162.12 

2 C HEATER REF_GAS 30440.13 

2 C HEATER REF_GAS 28672.09 

2 C HEATER REF_GAS 27970.11 

2 E HEATER, COKING PROCESS PROCESS GAS, REF GAS 48332.59 2 E HEATER, CRUDE UNIT PROCESS GAS, REF GAS 39770.77 2 E HEATER, COKING PROCESS PROCESS GAS, REF GAS 39577.84 2 E BOILER, HYDROGEN GENERATION REF GAS, NAT GAS 28868.34 2 E BOILER, STEAM GENERATION

REF GAS, PROCESS GAS FROM SCRUBBER 26484.59 

Total for 16 boilers/heaters (1 currently not in operation) 

3 EE

INCINERATOR (C54), CONTROL EQUIP FOR ABSORBER OF SULFUR RECOVERY UNIT

REF GAS, NAT GAS, PROCESS GAS 32995.62 

3 EE

INCINERATOR (C56), CONTROL EQUIP FOR ABSORBER OF SULFUR RECOVERY UNIT

REF GAS, NAT GAS, PROCESS GAS 11974.31 

3 B CONTROL DEVICE (C-910) THERMAL OXIDIZER

REFINERY GAS, NATURAL GAS, WASTE GAS 114337.58 

3 B CONTROL DEVICE, THERMAL OXIDIZER

REFINERY GAS, NATURAL GAS, WASTE GAS 111676.16 

3 F OXIDIZER 116994.68 

3 A

THERMAL OXIDIZER (D927), TAIL GAS IN SULFUR PRODUCTION UNIT NATGAS, REF GAS 75220.2 

3 A

THERMAL OXIDIZER (D927), TAIL GAS IN SULFUR PRODUCTION UNIT NATGAS, REF GAS 62774.65 
Final Staff Report – Part I Appendix A – 2005 S

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 245 

TABLE A-4 (Continued) 

Group Fac Name Description Fuel Type 2005 Emissions (lbs) 

3 A

THERMAL OXIDIZER (D911), TAIL GAS IN SULFUR PRODUCTION UNIT NATGAS, REF GAS 47309.99 

3 D OXIDIZER 112186.65 3 C

INCINERATOR (C456), SULFUR RECOVERY UNIT NO 2, TAIL GAS INCINERATOR REF GAS, NAT GAS 7518.47 

3 C

INCINERATOR (C436), SULFUR RECOVERY UNIT NO 1, TAIL GAS INCINERATOR REF GAS, NAT GAS 7005.95 

Total for 11 SRU/Tail Gas Units 

4 B FURNACE, SULFURIC ACID PLANT FUELOIL, NAT_GAS, SULFUR 821456.88 

4 A

REACTOR, SULFURIC ACID PRODUCTION, COMBUSTION CHAMBER PROCESS GAS 28304 

4 A

REACTOR, SULFURIC ACID PRODUCTION, COMBUSTION CHAMBER REFGAS, NATGAS 443.05 

Total for 3 Sulfuric Acid Manufacturing Reactors/Furnace 

5 BG FURNACE NAT_GAS 55242.68 

5 BG FURNACE, MELTING NAT_GAS, OXY-FUEL, PROPANE, GLASS 61637.19 

5 BG FURNACE, MELTING NAT_GAS, OXY-FUEL, PROPANE, GLASS 26411.28 

5 SG FURNACE, MELTING FUEL OIL, NAT_GAS, OXY FUEL, GLASS 93706.37 

Total for 4 Container Glass Melting Furnaces 

6 BW KILN, ROTARY, CALCINER PET COKE NATURAL GAS, DIESEL FUE: 257392.34 

Total for 1 coke calciner 

7 CC KILN COAL, COKE, FUEL OIL, NAT GAS, TIRE 140815.54 

7 CC KILN COAL, COKE, FUEL OIL, NAT GAS, TIRE 54045.06 

2 CC

BOILER, STEAM GENERATION, CIRCULATING FLUIIZED BED COAL, COKE, NAT GAS 1561.82 

Total for 2 cement kilns 

TOTAL 7 CATEGORIES OF EQUIPMENT 
Final Staff Report – Part I Appendix B – Summary of Federal, State and 

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 246 

Appendix B – Summary of Federal, State and Local SOx Rule Requirem(Summarized by Kevin Orellana) Fluid Catalytic Cracking Units Rule/Regulation Applicability Emission Limits Comp

Date 

SCAQMD R1105 FCCU 132 lbs SO2 per 1000 bbl feed (60-minute average) 1/1/19BAAQMD 9-1 FCCU 1000 ppmv SO2 3/15/1San Diego County APCD R53 

Other sources of gaseous sulfur emissions where sulfur compounds emitted are not products of fuel combustion 

0.05 % by volume dry, sulfur as SO2 1/22/1

NSPS 40 CFR Part 60 Subpart Ja 

FCCU 25 ppmv SO2 dry basis, 365-day rolling average 5/14/2

Sulfur Recovery Units/Tail Gas Units Rule/Regulation Applicability Emission Limits Comp

Date 

SCAQMD R468 SRU 500 ppm sulfur compounds (calculated as SO2 dry) 

over 15 minute average; and 10ppm H2S over 15-

minutes (dry); and 198.5 lbs./hr sulfur compounds as SO2

10/8/1

BAAQMD 9-1 SRU 250 ppmv SO2 dry @ 0% O2 3/15/1San Diego County APCD R53 

Sulfur recovery plants 0.05% by volume dry, sulfur as SO2 1/22/1

NSPS 40 CFR Part 60 Subpart Ja 

SRU with capacity >20 long tons/day, followed by incineration 

250 ppmv SO2 dry @ 0% O2 5/14/2

NSPS 40 CFR Part 60 Subpart Ja 

SRU with capacity >20 long tons/day, followed by incineration, with multiple trains or release points 

250 ppmv SO2 dry @ 0% O2 for each process train 

or release point; or comply with a flow-weighted average of 250 ppmv for all release points 

5/14/2

NSPS 40 CFR Part 60 Subpart Ja 

SRU with capacity >20 long tons/day, not followed by incineration 

10 ppmv H2S and 300 ppmv of reduced sulfur compounds (H2S, COS, and CS2), each calculated 

as ppmv of SO2 dry @ 0% O2

5/14/2
Final Staff Report – Part I Appendix B – Summary of Federal, State and 

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 247 

Refinery Boilers/Heaters Rule/Regulation Applicability Emission Limits Comp

Date 

NSPS 40 CFR Part 60 Subpart Ja 

Fuel gas combustion devices 

162 ppmv H2S in fuel gas determined hourly on a 3-hour rolling 

average basis or 60 ppmv in fuel gas determined daily on a 365 successive calendar day rolling average basis 

5/14/2

NSPS 40 CFR Part 60 Subpart Ja 

Fuel gas combustion devices 

20 ppmv flue gas SO2 (dry @ 0% O2) determined hourly on a 3-hour 

rolling average basis, and 8 ppmv flue gas SO2 (dry @0% O2) determined daily on a 365 successive calendar day rolling average basis 

5/14/2

SCAQMD R431.1 Fuel gas combustion 

devices 

40 ppmv averaged over 4 hours, calculated as H2S 5/4/19

SJVUAPCD R4301 Fuel burning equipment 200 lb/hr sulfur compounds, calculated as SO2 12/17Coke Calciners Rule/Regulation Applicability Emission Limits Comp

Date 

SCAQMD R1119 Coke Calcining At least 80% reduction of uncontrolled SOx 

emissions 

7/1/19

BAAQMD 9-1 Coke Calcining kilns 400 ppmv or 250 lb/hr SO2 3/15/1San Diego County APCD R53 

Other sources of gaseous sulfur emissions where sulfur compounds emitted are not products of fuel combustion 

0.05 % by volume dry, sulfur as SO2 1/22/1

Sulfuric Acid Plants Rule/Regulation Applicability Emission Limits Comp

Date 

SCAQMD R469 Sulfuric Acid 500 ppm sulfur compounds (calculated as 

SO2 dry) over 15 minute average; 198.5 

lbs./hr sulfur compounds as SO2

2/13/1

BAAQMD 9-1 Sulfuric acid plant equipment 300 ppmv SO2 @12% O2 3/15/1San Diego County APCD R53 

Other sources of gaseous sulfur emissions where sulfur compounds emitted are not products of fuel combustion 

0.05 % by volume dry, sulfur as SO2 1/22/1

NSPS 40 CFR Part 60 Subpart H 

Sulfuric Acid production units 4 lb SO2 per ton of acid produced (as 100% 

H2SO4) 

6/14/1
Final Staff Report – Part I Appendix B – Summary of Federal, State and 

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 248 

Cement Kilns Rule/Regulation Applicability Emission Limits Comp

Date 

San Diego County APCD R53 

Other sources of gaseous sulfur emissions where sulfur compounds emitted are not products of fuel combustion 

0.05 % by volume dry, sulfur as SO2

1/22/1

SJVUAPCD R4801 Any equipment that discharges gaseous sulfur compounds 0.2% by volume SO2 dry, over 

15 min-average 

12/17

Glass Manufacturing Rule/Regulation Applicability Emission Limits Comp

Date 

San Diego County APCD R53 

Other sources of gaseous sulfur emissions where sulfur compounds emitted are not products of fuel combustion 

0.05 % by volume dry, sulfur as SO2

1/22/1

SJVUAPCD R4354 Glass melting furnaces 0.90 lb SOx per ton glass 

produced (rolling 30-day average) 

1/1/20

Information related to the U.S. EPA Consent Decree for FCCUs are summarized below: Emission Limits Compliance Date BP: 50 ppmv SO2 @ 0% O2, 365-day rolling average; 

150 ppmv SO2 @ 0% O2, 7-day rolling average 

7/11/2005 

Tesoro: 36.2 ppmv SO2 @ 0% O2, 365-day rolling average; 

69.1 ppmv SO2 @ 0% O2, 7-day rolling average

2/2/2006 

Valero: No set limit at this time due to an ongoing demonstration project with SO2 reducing catalysts 

due by the compliance date. 

4/30/2011 

ExxonMobil: 25 ppmv SO2 @ 0% O2, 365-day rolling average; 

50 ppmv SO2 @ 0% O2, 7-day rolling average 

12/13/2005 

Chevron: 25 ppmv SO2 @ 0% O2, 365-day rolling average; 

50 ppmv SO2 @ 0% O2, 7-day rolling average 

12/31/2005 

ConocoPhillips: 25 ppmv SO2 @ 0% O2, 365-day rolling average; 

50 ppmv SO2 @ 0% O2, 7-day rolling average 

3/1/2011 
Final Staff Report – Part I Appendix C – C

_______________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 249 

Appendix C – CEMS Information & Source Test Data Table C-1: CEMS Data from a Refinery in the District – FCCU with Wet Gas Scrubber 

SOx 

Em issions

SOx 

Em issions

SOx 

Em issions

SOx 

Em issions

SOx 

Em issions

SOx 

Em issions

lbs/day Day lbs/day Day lbs/day Day lbs/day Day lbs/day Day lbs/day Day 

111.09 9/13/08 145.23 10/21/08 122.9 11/30/08 150.46 1/10/09 144.16 2/19/09 134.63 3/31/0111.02 9/14/08 143.99 10/22/08 125.16 12/1/08 150.58 1/11/09 143.64 2/20/09 136.42 4/1/0110.09 9/15/08 143.19 10/23/08 124.33 12/2/08 153.81 1/12/09 144.62 2/21/09 136.65 4/2/0109.51 9/16/08 143.22 10/24/08 123.61 12/3/08 155.46 1/13/09 145.55 2/22/09 138.37 4/3/0110.36 9/17/08 143.55 10/25/08 123.43 12/4/08 157.15 1/14/09 149.61 2/23/09 4/5/0119.47 9/18/08 143.89 10/26/08 123.25 12/5/08 157.49 1/15/09 155.25 2/24/09 181.74 4/6/0129.49 9/19/08 143.61 10/27/08 122.44 12/6/08 157.24 1/16/09 156.9 2/25/09 182.97 4/7/0130.41 9/20/08 143.3 10/28/08 123.13 12/7/08 158 1/17/09 153.88 2/26/09 174.53 4/8/0130.88 9/21/08 143.92 10/29/08 125 12/8/08 149.89 1/18/09 156.03 2/27/09 152.39 4/9/0130.75 9/22/08 143.73 10/30/08 123.15 12/9/08 147.05 1/19/09 155.04 2/28/09 127.02 4/10/0130.93 9/23/08 139.91 10/31/08 122.73 12/10/08 145.6 1/20/09 143.39 3/1/09 126.22 4/11/0131.86 9/24/08 130.97 11/1/08 122.37 12/11/08 146.31 1/21/09 139.42 3/2/09 130.46 4/12/0130.62 9/25/08 131.45 11/2/08 123.49 12/12/08 145.74 1/22/09 141.21 3/3/09 149.2 4/13/0130.69 9/26/08 133.77 11/3/08 123.68 12/13/08 150.03 1/23/09 141.9 3/4/09 152.12 4/14/0

125.6 9/27/08 131.73 11/4/08 135.92 12/15/08 158.61 1/24/09 141.2 3/5/09 150.03 4/15/0

132.65 9/28/08 131.32 11/5/08 139.17 12/16/08 157.7 1/25/09 142.64 3/6/09 150.28 4/16/0131.76 9/29/08 130.27 11/6/08 134.89 12/17/08 158.07 1/26/09 143 3/7/09 148.51 4/17/0128.53 9/30/08 132.76 11/7/08 135.66 12/18/08 158.49 1/27/09 142.89 3/8/09 147.04 4/18/0127.41 10/1/08 137.1 11/8/08 129.8 12/19/08 157.81 1/28/09 142.7 3/9/09 145.98 4/19/0129.48 10/2/08 138.25 11/9/08 130.95 12/20/08 154.73 1/29/09 141.86 3/10/09 146.36 4/20/0131.67 10/3/08 138.12 11/10/08 138 12/21/08 153.98 1/30/09 111.54 3/11/09 147.47 4/21/0132.49 10/4/08 137.22 11/11/08 132.16 12/22/08 155.43 1/31/09 48.03 3/12/09 148.87 4/22/0131.92 10/5/08 137.09 11/12/08 125.81 12/23/08 157.58 2/1/09 118.74 3/13/09 148.24 4/23/0131.33 10/6/08 137.11 11/13/08 134.23 12/24/08 155.16 2/2/09 36.04 3/14/09 149.37 4/24/0131.02 10/7/08 136.91 11/14/08 155.32 12/25/08 156.07 2/3/09 136.91 3/15/09 143.4 4/25/0119.64 10/8/08 135.62 11/15/08 156.05 12/26/08 155.67 2/4/09 143.78 3/16/09 125.06 4/26/0154.21 10/9/08 135.75 11/16/08 156.06 12/27/08 156.76 2/5/09 142.9 3/17/09 125.5 4/27/0154.71 10/10/08 135.71 11/17/08 157.29 12/28/08 156.1 2/6/09 125.63 3/18/09 131.39 4/28/0155.74 10/11/08 136.19 11/18/08 157.07 12/29/08 158.64 2/7/09 118.51 3/19/09 138.27 4/29/0156.58 10/12/08 137.07 11/19/08 155.95 12/30/08 159.41 2/8/09 119 3/20/09 138.9 4/30/0146.18 10/13/08 137.4 11/20/08 157.3 12/31/08 155.14 2/9/09 122.27 3/21/09 147.53 5/1/0128.23 10/14/08 137.14 11/21/08 160.33 1/1/09 160.87 2/10/09 130.06 3/22/09 148.7 5/2/0132.85 10/15/08 137.25 11/22/08 155.22 1/2/09 157.97 2/11/09 133.4 3/23/09 149.37 5/3/0140.19 10/16/08 137.81 11/23/08 141.5 1/3/09 151.77 2/12/09 134.39 3/24/09 149.34 5/4/0139.43 10/17/08 134.1 11/24/08 144 1/4/09 148.28 2/13/09 136.13 3/25/09 148.97 5/5/0140.03 10/18/08 125.09 11/25/08 147.65 1/5/09 143.42 2/14/09 136.69 3/26/09 148.51 5/6/0140.16 10/19/08 122.53 11/26/08 143.59 1/6/09 145.05 2/15/09 136.46 3/27/09 148.66 5/7/0143.02 10/20/08 122.32 11/27/08 141.79 1/7/09 150.44 2/16/09 136.49 3/28/09 149.02 5/8/0

122.14 11/28/08 154.11 1/8/09 149.17 2/17/09 138.11 3/29/09 149.51 5/9/0122.55 11/29/08 156.96 1/9/09 145.34 2/18/09 136.85 3/30/09 149.32 5/10/0

The concentration during 265 days (8.83 months) is 3.80 ppmv, however this refinery reported emissions basppmv. 
Final Staff Report – Part 1 Appendix D – Survey Questionnaire

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 250 November 2, 2010 

Table C-2: Source Test from a Refinery in the District - FCCU with Wet Gas Scrubber 

Test/Run ID 1 2 3 Average 

Date Tested NA 10/8/2008 10/9/2009 10/9/2008

Stack Oxygen % 1.30 1.28 1.27 1.28 

Stack Carbon Dioxide % 17.8 17.7 17.9 17.82

Average Stack Volumetric Flow (Methods 5 and 6) dscfm 128,982 128,276 124,384 127214 

Stack Temperature (Methods 5 and 6) oF 134 132 132 132.88

Stack Moisture Concentration (Methods 5 and 6) % 15.29 14.53 14.39 14.73

FCC Feed MBPD 49.19 48.93 48.93 49.02

FCC Feed MBPH 2.05 2.04 2.04 2.04

Coke Make (Burn) lb/hr 39,274 39,389 39,389 39,351 

Coke Make (Burn) Mlb/hr 39.27 39.39 39.39 39.35 

Catalyst Circulation Rate ton/min 45.41 46.25 46.25 45.97

Gas Flow to Scrubber/Circulation Ratio gal/MACF 26.23 25.94 25.94 26.04 

Total WESP Power KW 7.49 8.06 8.06 7.87 

#2 Lower WESP Spark Rate spk/min 1.34 1.30 1.30 1.31 

#1 Lower WESP Spark Rate spk/min 2.37 4.08 4.08 3.51 

#2 Upper WESP Spark Rate spk/min 0.00 0.00 0.00 0.00

#1 Upper WESP Spark Rate spk/min 0.00 0.00 0.00 0.00

Oxides of Nitrogen as NO2

 – Method 100.1 LIMIT(S)

as found ppmv 12.1 18.4 17.8 16.08 

at 3% O2 ppmv 11.0 16.8 16.2 14.7 

at 0% O2% ppmv 12.9 19.6 18.9 17.1 20

emission rate ppmv 11.3 17.2 16.1 14.9 

Carbon Monoxide – Method 100.1 

as found ppmv 40.9 39.6 43.5 41.3 

at 3% O2 ppmv 37.4 36.1 39.7 37.7 

emission rate lbs/hr 23.4 22.5 24.0 23.3 

VOC as Total Gaseous Non-Methane Organic – Method 25.3

VOC as TOC in Impinger Vial - Sample A ppmv 0.63

VOC as TGNMO in Canister - Sample A ppmv 50.1

Combined Vial and Canister Conc. - Sample A ppmv 50.73

VOC as TOC in Impinger Vial - Sample B ppmv 0.28

VOC as TGNMO in Canister - Sample B ppmv 65.9

Combined Vial and Canister Conc. - Sample B ppmv 66.18

as found-Average ppmv 58.46

at 3% O2 ppmv 53.39

emission rate lbs/hr 19.07

Sulfur Oxides as SO2– SCAQMD Method 6.1

Stack Volumetric Flow dscfm 128.071 123.830 121.962 124.621 

Isokinetic Sampling Rate (I) % 98 93 92 94 90<=I<=110

Stack Moisture Concentration % 15.97 15.44 15.18 15.53 

Stack Temperature oF oF 135 132 132 133 

Corrected Gas Volume Collected dscf 68.622 52.361 50.731 57.238 

SOx Conc. in Gas Sample ppmv 1.270 0.810 0.706 0.929 

SOx Conc. in Gas Sample at 3% O2 ppmv 1.160 0.739 0.644 0.848 

SOx Conc. in Gas Sample at 0% O2 ppmv 1.354 0.863 0.752 0.990 25 

SOx Emission Rate lb/hr 1.65 1.02 0.87 1.18 

SOx Emission (lb/1000 coke burn) lb/MB 0.04 0.03 0.02 0.03 9.80

Stack Particulate Matter (PM) – EPA Method 5 (Front 1⁄2)SCAQMD Method 5.2 (Back 1⁄2)

Stack Volumetric Flow dscfm 129,892 132,722 126,806 129,807 

Isokinetic Sampling Rate (I) % 103 104 102 103 90<=I<=110

Stack Moisture Concentration % 14.60 13.61 13.59 13.93 

Stack Temperature oF oF 134 132 133 133 

Corrected Gas Volume Collected dscf 183.457 189.314 177.602 183.458 

Stack Total PM Mass mg 42.60 34.55 34.45 37.20 

Stack Total PM - as found gr/dscf 0.00358 0.00282 0.00299 0.00313 

Stack Total PM at 3% O2 gr/dscf 0.00327 0.00257 0.00273 0.00286 

Stack Total PM emission rate lb/hr 3.99 3.20 3.25 3.48 

Stack Solid PM Mass mg 42.60 31.80 31.95 35.45 

Stack Solid PM - at found gr/dscf 0.00358 0.00259 0.00278 0.00298 

Stack Solid PM at 3% O2 gr/dscf 0.00327 0.00236 0.00253 0.00272 

Stack Solid PM Emission Rate lb/hr 3.99 2.95 3.02 3.32 

Stack PM Emission (lb/1000 bbl of feed) lb/MB 1.96 1.57 1.60 1.70 2.80

Stack PM Emission (lb/1000 coke burn) lb/MB 0.10 0.08 0.08 0.09 1.00
Final Staff Report – Part 1 Appendix D – Survey Questionnaire

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 251 November 2, 2010 

Table C-2: Source Test from a Refinery in the District - FCCU with Wet Gas Scrubber (Cont.) 

Inlet Particulate Matter (PM) – EPA Method 5

Inlet Volumetric Flow dscf 102,640 108,052 116,160 108,951 

Isokinetic Sampling Rate (I) % 92 103 92 96 990<=I<=110

Inlet Moisture Concentration % 16.39 16.10 10.20 14.23 

Inlet Temperature oF 561 570 567 566 

Corrected Gas Volume Collected dscf 27.307 32.356 30.980 30.214 

Inlet Total PM Mass mg 169.90 229.75 330.30 243.32 

Inlet Total PM - as found gr/dscf 0.09602 0.10958 0.16454 0.12338 

Inlet Total PM at 3% O2 gr/dscf 0.08770 0.09996 0.15006 0.11257 

Inlet PM emission rate lb/hr 84.47 101.49 163.82 116.59 
Final Staff Report – Part 1 Appendix D – Survey Questionnaire

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 252 November 2, 2010 

Appendix D – Survey Questionnaires 

Staff developed two Survey Questionnaires to collect information for this rule making process. The first 

Survey was sent out in 2008, and the second set of Survey was sent out in 2009. Please see below. 

 

SOx RECLAIM - SURVEY QUESTIONNAIRE 

July 23, 2009 

Please provide the following information by August 7, 2009. 

Water 

1. What is the current water usage and distribution at your facility (e.g. xx gal/year (xx%) used in cooling tower, xx gal/year 

(xx%) used in refinery processes)? 

2. Who is the water supplier for your facility? Does your facility have a maximum cap on the amount of water (fresh and 

recycled) that the facility can purchase from the supplier? If yes, please specify. 

3. How many groundwater wells does your facility have? How much is your facility permitted to pump and how much is your 

facility currently pumping? Please provide a copy of the groundwater permit for your facility. 

Wastewater

1. Your facility may own and operate its own wastewater treatment facility. What is the maximum capacity of this wastewater 

treatment facility? What is the normal rate of wastewater that your facility is currently handling? Please provide a brief 

description and schematic of the process. 

2. After treating the wastewater within your facility, where does the facility discharge the wastewater to? 

3. Does the facility send the wastewater to a third party for further treatment? If yes, who is this third party and what are the

average and maximum amount sent to this third party treatment facility? Is there any limit to the amount that your facility 

can send? 

4. Does your facility purchase recycled water to use in the processes at your facility? If yes, who is the supplier and what are 

the average and maximum amount that can be purchased? 

5. Who is the wastewater regulator for your facility? Please provide us a copy of your facility’s wastewater discharge permits. 

Solid Waste

1. How does the refinery currently handle the catalyst fines from the ESPs? Where are they shipped (or sold) to and what 

is the quantity? Are they considered hazardous waste? 

2. Who is the solid waste regulator for your facility? If your facility is subject to certain requirements on solid waste 

discharge, please provide a copy of the permits. 
Final Staff Report – Part 1 Appendix D – Survey Questionnaire

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 253 November 2, 2010 

South Coast Air Quality Management District 

SURVEY QUESTIONNAIRE 

FOR PROPOSED AMENDED REGULATION XX 

FURTHER SOx REDUCTION FOR RECLAIM 

(Request Due Date – February 21, 2008) 

Facility Contact 

1. Please provide the facility contact for this project: 

Name: 

Title: ______________________________________ 

Phone Number: 

Email Address: _____________________ 

Facility Top SOx Emitters 

2. Please list the top 10 SOx emitters at your facility and provide the following information. 

― Device description and device identification number 

― Emissions (tons per day) in 2005, 2006, 2007 

― SOx control technology used 

 

Operational Data 

3. Please provide the following information for the following seven specific equipment categories if they are on 

your facility’s list of top ten SOx emitters. 

Fluid Catalytic Cracking Units (FCCUs)

a) Please provide the following information: 

⎯ Feed rate, average and range (thousands barrels per day) 

⎯ Sulfur content of feed, average and range (percent by weight) 

⎯ Coke burn-off rate, average and range (thousand pounds per hour) 

⎯ FCCU catalyst manufacturer and catalyst recirculation rate (tons per hour) 

⎯ Average and range of flue gas exhaust flow rate from regenerator (millions dry standard cubic feet) and 

exhaust temperatures (degree Fahrenheit) 

⎯ Average and range of SOx concentration in the exhaust flue gas from the FCCU regenerator (ppmv at %O2) 

b) Does the facility currently use FCCU SOx reduction catalysts? If yes, please provide the following information: 

⎯ Name of catalyst manufacturer and name of SOx reduction catalyst 

⎯ Usage rate (pounds of catalysts added per day, or pounds of catalyst per pound of FCCU catalyst) 

⎯ Baseline SOx emissions and control efficiency. If available, please submit a copy of manufacturer's quote 

including specifications and guarantee 

⎯ Costs of SOx reduction catalysts. Please provide annual operating costs and any modification costs to the 

FCCU if needed in order to use the SOx reduction catalysts. 

⎯ When were the SOx reduction catalysts first used in the FCCUs and how long has the facility been using 

SOx reduction catalysts? 
Final Staff Report – Part 1 Appendix D – Survey Questionnaire

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 254 November 2, 2010 

c) Does the facility currently use, or plan to use, post combustion control device (e.g. wet scrubber)? If yes, please 

provide the following information: 

― Brief description of the technology (e.g. scrubber) 

― Design parameters (e.g. maximum flue gas flow rate, type of absorbent, absorbent flow rate, control 

efficiency, inlet and outlet ppmv, emission rate) 

― Capital costs and annual operating costs for the control technology 

― Installation date (or age of equipment) 

d) Please provide the most current source testing information (e.g. inlet and outlet ppmv, control efficiency, flue gas 

flow rate, emission rate, and test method). Please submit a copy of test reports or results if possible. 

Refinery Boilers, Refinery Heaters & Coal-Fired Fluidized Bed Boilers

a) Please provide the following information: 

⎯ Type of fuel used and fuel usage rate, range and average 

⎯ Sulfur content of fuel, range and average (percent by weight or ppmw) 

⎯ Flue gas exhaust flow rate, range and average (millions dry standard cubic feet) 

⎯ Annual average and range of the SOx concentrations in the exhaust flue gas (ppmv at 3%O2) 

b) Does the facility currently use any SOx control technology for the boiler/heater? If yes, please provide the 

following information: 

⎯ Brief description of the technology (e.g. scrubber) 

⎯ Design parameters (e.g. maximum flue gas flow rate, absorbent flow rate, control efficiency, inlet and outlet 

ppmv, emission rate) 

⎯ Capital costs and annual operating costs for the control technology 

⎯ Installation date (or age of equipment) 

c) Please provide the most current source testing information (e.g. inlet and outlet ppmv, control efficiency, flue gas 

flow rate, emission rate, and test method). Please submit a copy of test reports or results if possible. 

Sulfur Recovery & Tail Gas Treatment Units

a) Please provide the following information on the current operational data of the sulfur recovery and tail gas 

treatment units, including the thermal oxidizers, if appropriate: 

⎯ Brief description of the sulfur recovery & tail gas treatment unit including device identification number of 

the units in the system 

⎯ Current design and actual capacity of the sulfur recovery & treatment unit, range and average 

⎯ Sulfur content of feed, range and average (percent by volume or ppmv) 

⎯ Current sulfur removal efficiency of the system, and method used to determine the sulfur removal efficiency 

⎯ Flue gas exhaust flow rate, range and average (millions dry standard cubic feet) 

⎯ Annual average and range of the SOx concentrations in the exhaust flue gas 

⎯ Installation date (or age of equipment) 

b) Please provide the most current source testing information (e.g. inlet and outlet ppmv, control efficiency, flue gas 

flow rate, emission rate, and test method). Please submit a copy of test reports or results if possible. 
Final Staff Report – Part 1 Appendix D – Survey Questionnaire

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 255 November 2, 2010 

Sulfuric Acid Manufacturing Process

a) Please provide the following information: 

⎯ Brief description of the basic and control technique/equipment in the sulfuric acid manufacturing process 

(e.g. furnace, waste heat boiler, catalytic converter, ESP, absorber, scrubber etc) including device 

identification number 

⎯ Design and actual production rate (tons of acid produced) 

⎯ Type and input rate of raw materials (e.g. spent sulfuric acid, sulfur) 

⎯ Flue gas exhaust flow rate, range and average, (millions dry standard cubic feet) 

⎯ Range and average of SOx concentrations in the exhaust flue gas (ppmv) 

⎯ Annual average SOx emission rate (lbs SOx per ton of acid produced) 

b) Does the facility currently use SOx control technology for the process? If yes, please provide the following 

information: 

⎯ Brief description of the technology (e.g. dual absorption, wet gas scrubber) 

⎯ Design parameters (e.g. maximum flue gas flow rate, absorbent flow rate, control efficiency, inlet and outlet 

ppmv, emission rate) 

⎯ Capital costs and annual operating costs for the control technology 

⎯ Installation date (or age of equipment) 

c) Please provide the most current source testing information (e.g. inlet and outlet ppmv, control efficiency, flue gas 

flow rate, emission rate, and test method). Please submit a copy of test reports or results if possible. 

Container Glass Manufacturing Process – Melting Furnace

a) Please provide the following information: 

⎯ Design and actual capacity of each furnace (mmbtu/hr and tons of glass pulled) 

⎯ Type and input rate of raw materials (e.g. limestone, soda ash, cullet) 

⎯ Flue gas exhaust flow rate, range and average (millions dry standard cubic feet) 

⎯ Annual average and range of SOx concentrations in the exhaust flue gas (ppmv) 

⎯ Annual average emission rate for SOx (lbs SOx per ton of glass pulled) 

b) Does the facility currently use SOx control technology for the process? If yes, please provide the following 

information: 

⎯ Brief description of the technology (e.g. scrubber) 

⎯ Design parameters (e.g. maximum flue gas flow rate, absorbent flow rate, control efficiency, inlet and outlet 

ppmv, emission rate) 

⎯ Capital costs and annual operating costs for the control technology 

⎯ Installation date (or age of equipment) 

c) Please provide the most current source testing information (e.g. inlet and outlet ppmv, control efficiency, flue gas 

flow rate, emission rate, and test method). Please submit a copy of test reports or results if possible. 
Final Staff Report – Part 1 Appendix D – Survey Questionnaire

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 256 November 2, 2010 

Coke Calcining Kiln

a) Please provide the following information on the current operational data of the coke calciner (kiln): 

⎯ Maximum and average feed rate (tons per year and per day of green coke) 

⎯ Maximum and average production rate (tons per year and per day of calcined coke) 

⎯ Type of fuel used, and maximum and average fuel usage rate 

⎯ Maximum and average flue gas exhaust flow rate (millions dry standard cubic feet and) and stack 

temperatures (degree Fahrenheit) 

⎯ Range of outlet SOx concentrations (ppmv at % O2) and annual average 

⎯ Annual average SOx emission rate (lbs SOx per ton of glass pulled) 

b) Does the facility currently use SOx control technology for the process? If yes, please provide the following 

information: 

⎯ Brief description of the technology (e.g. dry scrubber) 

⎯ Design parameters (e.g. production rate, maximum treated flue gas, absorbent flow rate, control efficiency, 

inlet and outlet ppmv, emission rate in lbs SOx per ton coke) 

⎯ Capital costs and annual operating costs for the control system 

⎯ Installation date (or age of equipment) 

c) Please provide the most current source testing information (e.g. inlet and outlet ppmv, control efficiency, flue gas 

flow rate, emission rate, and test method). Please submit a copy of test reports or results if possible. 
Final Staff Report – Part 1 Appendix D – Survey Questionnaire

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 257 November 2, 2010 

Portland Cement Kiln

a) Please provide the following information on the current operational data of the Portland cement kiln 

⎯ Maximum and average feed rate of raw materials (tons per year and per day) 

⎯ Maximum and average production rate (tons per year and per day of calcined coke) 

⎯ Type of fuel used, and maximum and average fuel usage rate 

⎯ Maximum and average flue gas exhaust flow rate (millions dry standard cubic feet and) and stack 

temperatures (degree Fahrenheit) 

⎯ Range of outlet SOx concentrations (ppmv at % O2) and annual average 

b) Does the facility currently use any SOx control technology for the process? If yes, please provide the following 

information: 

⎯ Brief description of the technology (e.g. dry scrubber) 

⎯ Design parameters (e.g. production rate, maximum treated flue gas, absorbent flow rate, control efficiency, 

inlet and outlet ppmv, emission rate in lbs SOx per ton coke) 

⎯ Capital costs and annual operating costs for the control system 

⎯ Installation date (or age of equipment) 

c) Please provide the most current source testing information (e.g. inlet and outlet ppmv, control efficiency, flue gas 

flow rate, emission rate, and test method). Please submit a copy of test reports or results if possible. 

Reports Submitted Under the U.S. EPA Consent Decree 

4. If the facility must implement any control technology to further reduce SOx under a consent decree with the U.S. 

Environmental Protection Agency (EPA), please provide the District a copy of all reports and test results that the 

facility has been submitted to EPA on this subject. 

Other Feasible Control Technology 

5. Please provide the following information on any feasible control technology that could further reduce SOx from 

the above seven categories of equipment. 

⎯ A brief description of the technology, manufacturer's name, and control efficiency 

⎯ If available, estimated equipment costs, annual operating costs, cost effectiveness analysis, manufacturer's 

specifications, and guarantee 

⎯ If available, the facility’s name that currently uses or will use this technology. 

If you have any questions on the Survey Questionnaire, please contact: 

Minh Pham, P.E. 

Air Quality Specialist 

Phone: (909) 396-2613 

Email: mpham@aqmd.gov 
Final Staff Report – Part 1 Appendix E – Analysis for Rule 1105.1 Costs

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 258 November 2, 2010 

Appendix E – Analysis for Rule 1105.1 Costs. 

Note that to protect confidentiality, staff used different letters/numbers to refer to the different 

refineries and these are not the same as the letters/numbers used in the Staff Report of SOx 

RECLAIM and the Staff Report of Rule 1105.1. 

After Rule 1105.1 was adopted in November 3, 2003, the refineries installed control equipment to 

meet the PM10 and ammonia emission standards of Rule 1105.1. Four refineries selected to install 

dry electrostatic precipitators (ESPs) and one refinery installed a combination of a wet gas scrubber 

and a wet electrostatic precipitator (WGS/WESP). A summary of the control equipment 

manufacturers, contractors, construction period, and reported costs by the refineries is shown in 

below. Staff’s analysis comparing the reported costs and the estimated costs during the rule 

development is summarized below. 

Refinery Manufacturers Contractors Construction 

Period 

Reported 

Costs 

K ESP Hamon Research Cottrell Davenport Engineering 12/2007 – 05/2009 $ 44 M 

Y ESP Hamon Research Cottrell Jacobs Engineering 10/2007 – 01/2009 $ 340 M 

M ESP Hamon Research Cottrell Hamon Research Cottrell 1993 $ 23 M 

W ESP Hamon Research Cottrell Hamon Research Cottrell 2007 - 2008 $ 121 M 

X WGS/WESP ExxonMobil Jacobs Engineering 07/2007 – 09/2008 $ 59 M 

L ESP Hamon Research Cottrell Jacobs Engineering 11/2006 – 08/2008 $ 102 M 

 Total $ 666 M 

Refinery K 

During the development of Rule 1105.1 in 2003, Refinery K indicated that they did not have enough 

space to install dry ESPs but planned to install a WGS to comply with the proposed rule. Refinery K 

developed a cost estimate for the project including a BELCO WGS, a purge treatment unit, and 

induced draft fan to overcome pressure drop, a gas-to-gas heat exchanger to reheat the plume, and a 

wastewater treatment unit to handle the waste. The estimated costs for the project were $68 million 

dollars. A consultant hired by WSPA, NEXANT, reviewed the costs estimated by Refinery K, and 

added additional costs for demolition, modification of the SRU/TGs, electrical substation, and 

wastewater treatment, tie-in costs for NOx control, paving, and opportunity lost costs for extended 

turnaround. The result was an estimate of $78.7 million dollars capital costs as shown in Table 1.93

In 2007-2008, Refinery K decided to install ESPs, and they reported that the project cost was $43.8 

million as shown in Table 1. Fifty five percent of that cost, or approximately $36.8 million, was 

attributed to installation costs without identifying specific details. Refinery K indicated that they 

selected to install ESPs to save costs. The reported capital costs for the ESPs were about one halve 

of the estimated costs for the WGS project.94

 

93 An Evaluation of the Feasibility and Costs for Control of PM-10 Emissions at South Coast Refinery FCCUs 

(SCAQMD Proposed Rule 1105.1), NEXANT, Inc. for The Western States Petroleum Association, May 2003. 

94 E-mail communication from Refinery K to SCAQMD on February 10, 2010 and at March 18, 2010 site visit. 
Final Staff Report – Part 1 Appendix E – Analysis for Rule 1105.1 Costs

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 259 November 2, 2010 

TABLE 1 

Cost Estimates and Reported Capital Costs (Million Dollars) 

 Cost Estimates 

for WGS 

Reported Costs 

for ESPs

Difference 

Equipment Cost 68 7.0 10 times lower (68/7 = 9.7) 

Demolition 0.5 

Electrical Substation 0.8 36.8 3 times higher (36.8/10.7 = 3.4) 

Paving/Pile Driving 0.5 

Modification to wastewater 

treatment & SRU/TGs 

1.1 

Not needed 

NOx control tie-in 0.3 

Extended downtime 7.5 

Total Capital Costs 78.7 43.8 2 times lower (78.7/43.8 = 1.8) 

Refinery Y 

During the development of Rule 1105.1 in 2003, Refinery Y indicated that they would install a dry 

ESP to comply with the proposed rule. Refinery Y developed a cost estimate for the project 

including a Hamon Research Cottrell’s ESP. There were also extensive costs for ducting/piping and 

site modification since Refinery Y planned to install the ESP far away from the FCCU. WSPA’s 

consultant reviewed Refinery Y’s cost estimates and added costs for additional ducting and supports, 

insulation, asbestos abatement, SCR/stack relocation, new foundations and paving, electrical 

instrumentation and controls, piping relocation, and demolition. The estimated capital costs were 

$48.9 million.95 In 2007-2008, Refinery Y installed ESPs. Refinery Y reported that the total cost of 

the project was $340 million. The estimated costs and reported costs are presented in Table 2.96

The substantial differences in the reported costs and the cost estimates are shown in Table 2. The 

reported equipment costs are 35% higher than the estimated costs. The site preparation costs are 

almost the same as estimated. There are substantial differences in the installation costs including 

ducting, supports, electrical substation modification, and engineering/management costs. The 

reported installation costs are 30 times higher than estimated, and the overall reported costs are 7 

times higher than estimated. 

 

95 An Evaluation of the Feasibility and Costs for Control of PM-10 Emissions at South Coast Refinery FCCUs 

(SCAQMD Proposed Rule 1105.1), NEXANT, Inc. for The Western States Petroleum Association, May 2003 

96 E-mail communication from Refinery Y to SCAQMD on July 7, 2010. Refinery Y reported the following: 

equipment/materials ($54 million), installation/demolition ($5 million), civil ($25 million), mechanical - 

steel/piping/ESP assembly ($109 million), electrical and instrumentation ($17 million), support crafts - cranes, 

scaffolding etc. ($60 million), and engineering and construction management ($75 million). 
Final Staff Report – Part 1 Appendix E – Analysis for Rule 1105.1 Costs

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 260 November 2, 2010 

TABLE 2 

Cost Estimates and Reported Capital Costs (Million Dollars) 

Refinery # M 

Refinery M installed a new ESP in 1993. Total capital costs were $13.6 million.98 At a 3% inflation 

rate, the capital costs would be approximately $23 million in current dollars.99 

TABLE 3 

Reported Capital Costs (Million Dollars) 

 Reported Costs 

Equipment Costs 5.83 

Installation Costs 7.80 

Total Capital Costs 13.63 (about 23 today) 

 

97 The actual costs of $186 million = 109+60+17 

98 Fax communication from Refinery M to SCAQMD on March 9, 1995: Materials = $5,837,000; Engineering = 

$1,946,000; Construction labor = $4,610,000; Miscellaneous = $1,240,000; and Total Costs = $13.6 million. 

99 The Chemical Engineering Plant Cost Annual Index and the Marshall & Swift Cost Index show that there was a 3% 

inflation rate from 1993 to 2005. With a 3% inflation rate, the costs in current dollars would be (14) (1.03) exp (2010-

1993) = (14) (1.03) exp (17) = (14) (1.65) = $23 million. In a recent e-mail communication with the SCAQMD on 

February 19, 2010, Refinery M used a 7% inflation rate to estimate the costs at (14)(1.07) exp(2010-1993) = $45 million 

and claimed the costs would be $60 million with extra compliance flexibility. 

 Cost Estimates Reported Costs Difference 

Equipment Cost 40 54 35% higher (54/40=1.35) 

Ducting/Support/ Insulation 4.8 186 97 30 times higher (186/5.55=30.5)

Induced fans 0.35 

Electrical Substation 0.4 

Demolition 2 

25 

Almost the same (25/23=1.1) 

Asbestos Removal 0.15 

Contaminated Soil Disposal 0.1 

Foundations/Paving 0.75 

Site Upgrade 20 

Engineering/Management Included above 75 --- 

SCR relocation 0.35 Not needed --- 

Total Capital Costs 48.9 340 7 times higher (340/48.9 = 6.95)
Final Staff Report – Part 1 Appendix E – Analysis for Rule 1105.1 Costs

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 261 November 2, 2010 

Refinery W 

During the development of Rule 1105.1 in 2003, Refinery W indicated that they would install a dry 

ESP to comply with the proposed rule. Refinery W and WSPA’s consultant developed a cost 

estimate for the project including a large ESP and extensive costs for ducting, relocation of a 

roadway, underground sewers and drains, piling, disposal of contaminated soil, new electrical 

substation, SCR, engineering/management, and extended shutdown. The estimated capital costs were 

$38 million. 100 In 2007-2008, Refinery W installed 3 ESPs and reported that the total cost of the 

project was $121.3 million. 101 The estimated costs and reported as actual costs by Refinery W are 

presented in Table 4. 

The reported equipment costs and engineering costs are about 2 times higher than estimated. 

However, there are substantial differences in the construction and installation costs including 

ducting, supports, electrical substation modification etc., which cause the reported installation costs 

to rise up to 9 times higher than estimated, and the overall reported costs 4 times higher than 

estimated. 

TABLE 4 

Cost Estimates and Reported Capital Costs (Million Dollars) 

 Cost Estimates Reported Costs Difference 

Equipment Cost 8 – 12 15 2 times higher (15/8=1.9) 

SCR 10 Not specified --- 

Site preparation and 

Construction 

9.1102 95.4 9 times higher 

(95.4/10.5=9.1) 

Electrical Substation 1.4 

Engineering/Management 4.8 10.9 2 times higher (10.9/4.8=2.3) 

Extended turnaround 2.7 Not needed 

Total Capital Costs 38.0 121.3 4 times higher (121/33=3.67) 

 

100 An Evaluation of the Feasibility and Costs for Control of PM-10 Emissions at South Coast Refinery FCCUs 

(SCAQMD Proposed Rule 1105.1), NEXANT, Inc. for The Western States Petroleum Association, May 2003. 

NEXANT estimated ESP costs from $8 - $12 million. Site preparation costs included relocating a refinery road 

($400,000), relocating sewers/drains/piping ($650,000), disposal of contaminated soil ($100,000), piling ($350,000), and 

35% contingency ($7.6 million). New electrical substation was added ($800,000) and existing distribution system was 

modified ($600,000). Engineering and management costs were estimated ($800,000) and owners costs ($4 million) 

101 E-mail communication from Refinery W to SCAQMD on March 30, 2010. Refinery W reported the following 

costs: equipment/materials ($15 million), construction ($62.6 million), material ($21.3 million), incentive ($1.2 

million), pre-capital expense ($2.9 million) + demolition ($2.9 million), engineering ($10.9 million) and owner’s costs 

($4.5 million) 

102 This footnote is to estimate the estimations in Table 4. Site preparation = 0.4+ 0.65+0.35+0.10+ 7.6 = 9.1. Electrical 

substation = 0.8+0.6 = 1.4. Engineering Management = 0.8+4.0 = 4.8. Construction costs = 

62.6+21.3+1.2+4.5+2.9+2.9=95.4. In Table 5, Construction costs = 24.4+ 7.9+ 1.0 = 33.3. In Table 6, 
Final Staff Report – Part 1 Appendix E – Analysis for Rule 1105.1 Costs

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 262 November 2, 2010 

Refinery X 

In 2003, Refinery X planned to install 2 ESPs and 2 SCRs to meet R.1105.1 limits at the costs of $43 

million.103 However, in 2007-2008, Refinery X decided to install a WGS at the costs of $58.9 

million.104 The estimated and reported costs are provided in Table 5. 

TABLE 5 

Cost Estimates and Reported Capital Costs (Million Dollars) 

 Cost Estimates Reported Costs Difference 

Equipment Cost 28 18.9 35% higher (18.9/14 = 1.35) 

CO boiler or SCR 10 Not included 

Ducting/Support & 

Insulation 

3.1 33.3 6 times higher (33.3/5.3 = 6.3) 

Electrical Substation 0.8 

Asbestos Removal 0.1 

Contaminated Soil 

Disposal 

0.1 

Owner’s Costs 1.2 6.7 6 times higher (6.7/1.2 = 5.6) 

Total Capital Costs 43.3 58.9 2 times higher (58.9/33.3 = 1.8) 

Comparing the two estimates, the costs for the WGS/WESP ($18.9 million including a $5 million 

cost for a fin fan cooler) is about the same as a single, large ESP ($14 million). 

The major differences in the 2010 reported as actual costs and the 2003 estimates are in the 

installation and owner’s costs. The reported installation costs including construction, demolition, 

and engineering and the reported owner’s costs are approximately 6 times higher than 2003 

estimates. The overall 2010 reported costs are approximately 2 times higher than the 2003 estimates 

(not including the SCRs), and three times higher than the ESP costs. 

Refinery L 

During the development of Rule 1105.1, Refinery L indicated that they would install ESPs to meet 

the requirements of Rule 1105.1. Refinery L hired a consultant (Jacobs Engineering) to develop a 

feasibility and cost estimate to comply with the proposed Rule 1105.1 limit for both ESPs and WGS. 

Jacobs Engineering recommended Refinery L to select dry ESPs, and they designed the ESPs with 

25% larger collecting area. In their estimates, they assumed the costs of project engineering and 

 

103 An Evaluation of the Feasibility and Costs for Control of PM-10 Emissions at South Coast Refinery FCCUs 

(SCAQMD Proposed Rule 1105.1), NEXANT, Inc. for The Western States Petroleum Association, May 2003. The 

costs were estimated for two new ESPs in parallel, 200% capacity total, with two new SCRs. 

104 E-mail from Refinery X to SCAQMD on March 19, 2020. Refinery X reported the following: equipment/materials 

($18.9 million), construction ($24.4 million), engineering ($7.9 million), demolition ($1 million), and owner’s costs 

($6.7 million). 
Final Staff Report – Part 1 Appendix E – Analysis for Rule 1105.1 Costs

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 263 November 2, 2010 

services averaged 18.7% of the total capital costs. The total estimated costs are $57 million 

dollars.105 The cost estimates are presented in Table 12-3-6. 

In 2007-2008, Refinery L installed ESPs. The costs of $102 million dollars reported as the actual 

costs for this project provided by Refinery L are presented in Table 6. 106

TABLE 6 

Cost Estimates and Reported Capital Costs (Million Dollars) 

 Cost Estimates Reported Costs Difference 

Equipment Cost 10 17.547 2 times higher (17.5/10 = 1.8) 

Project Management 10.66 6.23 

Engineering 9.27 2 times higher (15.5/10.66 = 1.5)

Construction Indirects 

36.34 

15.60 

2 times higher (69.1/36.3 = 1.9) 

Construction Directs 45.202 

Start –Up 2.269 

Demolition 0.378 

Other Costs 5.635 

Total Capital Costs 57 102.135 2 times higher (102/57 = 1.8) 

The differences in the 2010 reported costs and the 2003 estimates are shown in Table 6. The 

reported equipment costs, installation costs, and capital costs are consistently about 2 times higher 

than the 2003 estimates. 

Summary & Staff’s Analysis 

A comparison of the costs reported by the refineries as actual costs, and the estimated costs during 

the rule development process are provided in Table 7 and staff’s analysis is as follows.

Equipment Costs 

The reported equipment costs are not much different than estimated. The reported costs are about 

35% higher for Refinery Y and Refinery X, 2 times higher for Refinery W and L, and 10% lower for 

Refinery K. The differences are due to inflation (about 3% between 2003 and 2010), extra capacity 

for redundancy built in the design, and the price surge of steel in 2007-2008 time frames. 

 

105 An Evaluation of the Feasibility and Costs for Control of PM-10 Emissions at South Coast Refinery FCCUs 

(SCAQMD Proposed Rule 1105.1), NEXANT, Inc. for The Western States Petroleum Association, May 2003. The 

costs were estimated for a large ESP with 25% more capacity. 

106 E-mails communication from Refinery L to SCAQMD on January 27, 2010 and February 08, 2010 provide detailed 

information in cost breakdown. Staff combined the costs provided into these following categories a) Project Management 

includes contractor costs ($5.760 million) and owner costs ($0.471 million); b) Engineering costs include contractor costs 

($9.264 million) and owner costs ($0.01 million); c) Construction Indirect Owner Costs of $1.050 million is for temporary 

facilities/services/utilities. Construction Indirect Contractor Costs of $14.549 million includes construction management 

($6.349 million), equipment not provided by sub-contractors ($4.303 million), and temporary facilities/services/utilities 

($3.898 million); d) ISBL Construction Directs of $62.719 million include equipment ($17.547 million); civil/site ($0.419 

million), concrete ($0.901 million), steel ($6.331 million), piping ($3.915 million), process air ($2.479 million), electrical 

($19.120 million), process control ($5.719 million), paint/insulation/fireproofing ($6.317 million) 
Final Staff Report – Part 1 Appendix E – Analysis for Rule 1105.1 Costs

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 264 November 2, 2010 

WGS/WESP versus ESPs 

Refinery X planned to use ESPs but installed a WGS. Refinery K planned to use WGS but installed 

ESPs. Refinery X data shows that there is no difference in the equipment costs of a WGS/WESP/fin 

fan cooler system versus two ESPs to meet the requirement of Rule 1105.1 and also to mitigate the 

plume if necessary. Refinery K data shows that the equipment costs for ESPs are 10 times lower 

than the costs for a WGS system. It seems that Refinery K over-estimated the costs of their WGS 

system by building a larger unit than necessary, adding a new wastewater treatment to handling the 

waste that could be handled by the purge treatment system, and using a gas-to-gas reheat exchanger 

instead of a fin-fan cooler. 

TABLE 7 

Cost Estimates and Reported Costs (Million Dollars) 

 Ref M Ref K Ref Y Ref W Ref X Ref L Total 

Estimated Capital Costs --- 78.7 48.9 38.0 43.3 57.0 266.0 

Reported Equipment Costs 7.0 7.0 54.0 15 18.9 17.5 119.4 

Reported Capital Costs 107 23.0 43.8 340.0 121.3 58.9 102 666.0 

 Reported Capital Costs

Estimated Capital Costs --- 0.6 7.0 4.0 1.8 1.8 2.5 (average) 

Reported Capital Costs (2010)

Reported Equipment Cost 

(2010) 

2.0 6.3 6.2 8.1 3.1 5.8 5.6 

(average) 

Installation Costs 

There are substantial differences in reported installation costs versus estimated installation costs: 2 

times higher for Refinery L, 3 times higher for Refinery K, 6 times higher for Refinery X, 9 times 

higher for Refinery W, and 30 times higher for Refinery Y. Note that site preparation did not cause 

this substantial difference in Refinery Y case. The vast differences originate from ducting, supports, 

electrical substation modification, engineering, management, and labor costs. Refinery L provided 

the following explanations which may apply to other refineries as well: 108

⎯ Materials Costs. The reported cost includes a) steel, concrete, site excavation, painting, 

fireproofing for foundation and buildings, b) insulation for ducting/piping, c) substantial amount 

for wiring/conduit for substation and power distribution, and d) substantial amount for 

instrument/controls. These categories are underestimated in 2003, especially the costs for steel, 

electrical wiring, and instrument/controls. Costs of steel increased by at least 2 in 2008 time 

frame. 

 

107 WSPA’s estimates are in the neighborhood of $750 million based on a wrong estimate for Refinery M at $60 million 

using 7% inflation rate and $70 million AFE costs for Refinery X. That is, 43.8 + 340 + 60 + 121.3 + 70 + 102.1 = $742 

million. Refinery X actual installation costs are only $58.9 million. 

108 E-mail communication from Refinery L to SCAQMD on May 27, 2010. 
Final Staff Report – Part 1 Appendix E – Analysis for Rule 1105.1 Costs

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 265 November 2, 2010 

⎯ Inflation. Construction was completed in 2008, and during 2008, there was a period of hyper 

inflation in heavy industrial construction equipment and labor costs. 

⎯ Union Labor Costs. Due to the volume of construction activity in late 2007 to early 2008, union 

construction resources were used while the estimate in 2003 was based on non-union 

construction labor. There is an overall cost differential of over 30% between non-union and 

union labor forces. 

⎯ Compressed Construction Schedule. To meet a FCCU turnaround date, the construction 

schedule was accelerated. It is important to note that the litigation filed by WSPA immediately 

after Rule 1105.1 was adopted in November 2003, and subsequent appeal of the original 

judgment, contributed significantly in further compressing the construction schedule. All five 

refineries delayed the construction of the control equipment until WSPA finally lost the law suit 

in late 2006. This scheduling constraints in conjunction with the limited number of control 

equipment vendors/manufacturers and contractors that the refineries selected to contract with for 

this project contributed substantially to the price escalation. 

⎯ Redundancy. In order for the vendor to guarantee R1105.1 level of particulate capture, the 

vendor had to add extra capacity to the ESP, larger than estimated in 2003. 

Capital Costs 

Overall, the reported capital costs are higher than estimated: 2 times higher for Refinery K, X and L, 

4 times higher for Refinery W, and 7 times higher for Refinery Y. On average, the reported capital 

costs are 2.5 times higher than estimated. 

Refinery Y and W are the two outliers from the average with reported costs about 2-3 times higher 

than other refineries: 

⎯ Refinery Y’s total gas flow rate (540,111 acfm reported in 2003) is about 25% higher than 

Refinery L’s (436,035 acfm total gas flow)109 however the equipment costs of Refinery Y ($54 

million) is about 3 times higher than that of Refinery L ($17.5 million), and their reported capital 

costs ($340 million) is also about 3 times higher than Refinery L’s ($102 million). 

⎯ Refinery W’s total gas flow rate (218,628 acfm reported in 2003) is about the same as Refinery 

K’s (212,514 acfm total gas flow) however the reported equipment costs of Refinery W ($15 

million) is about 2 times higher than Refinery K’s ($7 million), and their capital costs ($121 

million) is about 3 times higher than Refinery K’s ($43.8 million). 

⎯ Refinery Y and #4 did seem to add extraordinary capacity to their ESPs and upgrade other 

systems at their sites along with installing the ESPs.

 

109 SP Environmental Report, August 2003.
Final Staff Report – Part 1 Appendix E – Analysis for Rule 1105.1 Costs

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 266 November 2, 2010 

Comparison between Costs Reported As Actual Capital Costs and Equipment Costs 

The costs reported by the refineries as actual capital costs are 2 times higher than the equipment 

costs for Refinery M, 3 times higher for Refinery X, 6 times higher for Refinery K, Y, and L, and 8 

times higher for Refinery W. It is interesting to note that there are two distinct groups: Refinery M 

and X, with a ratio between 2 and 3, and Refinery K, Y, W and L with a ratio between 6 and 8. It 

appears that Refinery K, Y, W and L may have spent additional money on upgrading other existing 

systems (ducting, supports, electrical substation modification, NOx/SOx CEMS) and used more in 

engineering and management compared to Refinery X and L. However, on average, the reported 

capital costs are about 5-6 times higher than the equipment costs. It is important to note that the 

consultants hired to assist staff with the BARCT and cost analysis of the proposed amended 

Regulation XX (SOx RECLAIM), namely ETS, Inc., AEC and NEC, have used a ratio of 5x in 

their cost analyses for refineries. 

 
Final Staff Report – Part 1 Appendix F – U.S. Refineries Operable Capacities

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 267 November 2, 2010 

Appendix F – U.S. Refineries Operable Capacities 

(Reference: U.S. Energy Information Administration) 

RANK CORPORATION COMPANY STATE SITE Barrels per 

Calendar Day

1 EXXON MOBIL CORP EXXONMOBIL REFINING & SUPPLY CO Texas BAYTOWN 560,640

2 EXXON MOBIL CORP EXXONMOBIL REFINING & SUPPLY CO Louisiana BATON ROUGE 504,500

3 BP PLC BP PRODUCTS NORTH AMERICA INC Texas TEXAS CITY 437,080

4 MARATHON OIL CORP MARATHON PETROLEUM CO LLC Louisiana GARYVILLE 436,000

5 PDV AMERICA INC CITGO PETROLEUM CORP Louisiana LAKE CHARLES 429,500

6 BP PLC BP PRODUCTS NORTH AMERICA INC Indiana WHITING 405,000

7 WRB REFINING LLC WRB REFINING LLC Illinois WOOD RIVER 362,000

8 EXXON MOBIL CORP EXXONMOBIL REFINING & SUPPLY CO Texas BEAUMONT 344,500

9 SUNOCO INC SUNOCO INC (R&M) Pennsylvania PHILADELPHIA 335,000

10 CHEVRON CORP CHEVRON USA INC Mississippi PASCAGOULA 330,000

11 DEER PARK REFINING LTD 

PTNRSHP DEER PARK REFINING LTD PARTNERSHIP Texas DEER PARK 327,000

12 KOCH INDUSTRIES INC Flint Hills Resources LP Texas CORPUS CHRISTI 290,078

13 VALERO ENERGY CORP PREMCOR REFINING GROUP INC Texas PORT ARTHUR 287,000

14 MOTIVA ENTERPRISES LLC Motiva Enterprises LLC Texas PORT ARTHUR 285,000

15 ACCESS INDUSTRIES HOUSTON REFINING LP Texas HOUSTON 280,700

16 KOCH INDUSTRIES INC Flint Hills Resources LP Minnesota SAINT PAUL 280,500

17 CHEVRON CORP CHEVRON USA INC California EL SEGUNDO 265,500

18 BP PLC BP West Coast Products LLC California LOS ANGELES 265,000

19 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY Louisiana BELLE CHASSE 247,000

20 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY Texas SWEENY 247,000

21 CHEVRON CORP CHEVRON USA INC California RICHMOND 245,271

22 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY Louisiana WESTLAKE 239,400

23 EXXON MOBIL CORP EXXONMOBIL REFINING & SUPPLY CO Illinois JOLIET 238,600

24 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY New Jersey LINDEN 238,000

25 MOTIVA ENTERPRISES LLC Motiva Enterprises LLC Louisiana CONVENT 235,000

26 MOTIVA ENTERPRISES LLC Motiva Enterprises LLC Louisiana NORCO 234,700

27 TOTAL SA TOTAL PETROCHEMICALS INC Texas PORT ARTHUR 232,000

28 BP PLC BP West Coast Products LLC Washington FERNDALE 225,000

29 KOCH INDUSTRIES INC FLINT HILLS RESOURCES ALASKA LLC Alaska NORTH POLE 219,500

30 VALERO ENERGY CORP VALERO REFINING CO TEXAS LP Texas TEXAS CITY 214,000

31 MARATHON OIL CORP MARATHON PETROLEUM CO LLC Kentucky CATLETTSBURG 212,000

32 MARATHON OIL CORP MARATHON PETROLEUM CO LLC Illinois ROBINSON 206,000

33 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY Oklahoma PONCA CITY 198,400

34 CHALMETTE REFINING LLC Chalmette Refining LLC Louisiana CHALMETTE 192,500

35 VALERO ENERGY CORP VALERO REFINING NEW ORLEANS LLC Louisiana NORCO 185,003
Final Staff Report – Part 1 Appendix F – U.S. Refineries Operable Capacities

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 268 November 2, 2010 

36 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY Pennsylvania TRAINER 185,000

37 VALERO ENERGY CORP PREMCOR REFINING GROUP INC Tennessee MEMPHIS 180,000

38 SUNOCO INC SUNOCO INC Pennsylvania MARCUS HOOK 178,000

39 VALERO ENERGY CORP VALERO ENERGY CORPORATION Texas SUNRAY 171,000

40 PDV AMERICA INC PDV Midwest Refining LLC Illinois LEMONT 167,000

41 TESORO CORP TESORO REFINING & MARKETING CO California MARTINEZ 166,000

42 PDV AMERICA INC CITGO REFINING & CHEMICAL INC Texas CORPUS CHRISTI 163,000

43 SUNOCO INC SUNOCO INC Ohio TOLEDO 160,000

44 VALERO ENERGY CORP VALERO REFINING CO NEW JERSEY New Jersey PAULSBORO 160,000

45 ROYAL DUTCH/SHELL GROUP Shell Oil Products US California MARTINEZ 156,400

46 HUSKY ENERGY INC LIMA REFINING COMPANY Ohio LIMA 150,000

47 EXXON MOBIL CORP EXXONMOBIL REFINING & SUPPLY CO California TORRANCE 149,500

48 WRB REFINING LLC WRB REFINING LLC Texas BORGER 146,000

49 ROYAL DUTCH/SHELL GROUP Shell Oil Products US Washington ANACORTES 145,000

50 VALERO ENERGY CORP VALERO REFINING CO CALIFORNIA California BENICIA 144,000

51 VALERO ENERGY CORP VALERO REFINING CO TEXAS LP Texas CORPUS CHRISTI 142,000

52 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY California WILMINGTON 139,000

53 FRONTIER OIL REFINING & 

MKTG FRONTIER EL DORADO REFINING CO Kansas EL DORADO 130,000

54 BP HUSKY REFINING LLC BP-HUSKY REFINING LLC Ohio TOLEDO 125,700

55 WESTERN REFINING INC. WESTERN REFINING COMPANY LP Texas EL PASO 122,000

56 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY California RODEO 120,200

57 MURPHY OIL CORP MURPHY OIL USA INC Louisiana MERAUX 120,000

58 TESORO CORP Tesoro West Coast Washington ANACORTES 120,000

59 CVR ENERGY INC COFFEYVILLE RESOURCES RFG & MKTG LLC Kansas COFFEYVILLE 115,700

60 MARATHON OIL CORP MARATHON PETROLEUM CO LLC Michigan DETROIT 106,000

61 HOLLY CORP NAVAJO REFINING CO New Mexico ARTESIA 105,000

62 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY Washington FERNDALE 100,000

63 PETROLEO BRASILEIRO SA PASADENA REFINING SYSTEMS INC Texas PASADENA 100,000

64 TESORO CORP TESORO REFINING & MARKETING CO California WILMINGTON 96,860

65 TESORO CORP TESORO HAWAII CORP Hawaii EWA BEACH 93,500

66 VALERO ENERGY CORP VALERO ENERGY CORPORATION Texas THREE RIVERS 93,000

67 VALERO ENERGY CORP VALERO REFINING CO OKLAHOMA Oklahoma ARDMORE 87,400

68 CHS INC NCRA Kansas MCPHERSON 85,500

69 HOLLY CORP HOLLY REFINING & MARKETING CO Oklahoma TULSA WEST 85,000

70 VALERO ENERGY CORP VALERO REFINING CO TEXAS LP Texas HOUSTON 83,000

71 VALERO ENERGY CORP VALERO REFINING CO CALIFORNIA California WILMINGTON 

REFINERY 80,887

72 ALON ISRAEL OIL COMPANY 

LTD ALON REFINING KROTZ SPRINGS INC Louisiana KROTZ SPRINGS 80,000

73 CHEVRON CORP CHEVRON USA INC New Jersey PERTH AMBOY 80,000

74 ROYAL DUTCH/SHELL GROUP SHELL CHEMICAL LP Alabama SARALAND 80,000

75 TRANSWORLD OIL USA INC CALCASIEU REFINING CO Louisiana LAKE CHARLES 78,000
Final Staff Report – Part 1 Appendix F – U.S. Refineries Operable Capacities

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 269 November 2, 2010 

76 MARATHON OIL CORP MARATHON PETROLEUM CO LLC Ohio CANTON 78,000

77 MARATHON OIL CORP MARATHON PETROLEUM CO LLC Texas TEXAS CITY 76,000

78 ERGON INC LION OIL CO Arkansas EL DORADO 75,000

79 MARATHON OIL CORP MARATHON PETROLEUM CO LLC Minnesota SAINT PAUL 74,000

80 SINCLAIR OIL CORP SINCLAIR WYOMING REFINING CO Wyoming SINCLAIR 74,000

81 TESORO CORP TESORO ALASKA PETROLEUM CO Alaska KENAI 72,000

82 HOLLY CORP HOLLY REFINING & MARKETING CO Oklahoma TULSA EAST 70,300

83 GARY WILLIAMS CO WYNNEWOOD REFINING CO Oklahoma WYNNEWOOD 70,000

84 ALON ISRAEL OIL COMPANY 

LTD ALON USA ENERGY INC Texas BIG SPRING 67,000

85 SUNCOR ENERGY INC SUNCOR ENERGY (USA) INC Colorado COMMERCE CITY 

WEST 67,000

86 WESTERN REFINING INC. WESTERN REFINING YORKTOWN INC Virginia YORKTOWN 66,300

87 FLYING J INC BIG WEST OF CALIFORNIA California BAKERSFIELD 66,000

88 UNITED REFINING INC UNITED REFINING CO Pennsylvania WARREN 65,000

89 EXXON MOBIL CORP EXXONMOBIL REFINING & SUPPLY CO Montana BILLINGS 60,000

90 CHS INC Cenex Harvest States Coop Montana LAUREL 59,600

91 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY Montana BILLINGS 58,000

92 DELEK GROUP LTD DELEK REFINING LTD Texas TYLER 58,000

93 TESORO CORP Tesoro West Coast North Dakota MANDAN 58,000

94 TESORO CORP Tesoro West Coast Utah SALT LAKE CITY 58,000

95 CALUMET LUBRICANTS CO CALUMET SHREVEPORT LLC Louisiana SHREVEPORT 57,000

96 PLACID OIL CO PLACID REFINING CO Louisiana PORT ALLEN 57,000

97 ARCTIC SLOPE REGIONAL CORP PETRO STAR INC Alaska VALDEZ 55,000

98 ROYAL DUTCH/SHELL GROUP SHELL CHEMICAL LP Louisiana SAINT ROSE 55,000

99 CHEVRON CORP CHEVRON USA INC Hawaii HONOLULU 54,000

100 ALON ISRAEL OIL COMPANY 

LTD PARAMOUNT PETROLEUM CORPORATION California PARAMOUNT 53,000

101 FRONTIER OIL REFINING & 

MKTG FRONTIER REFINING INC Wyoming CHEYENNE 47,000

102 CHEVRON CORP CHEVRON USA INC Utah SALT LAKE CITY 45,000

103 COMPAGNIE NATIONALE AÂ 

PORTEFEUILLE US OIL & REFINING CO Washington TACOMA 37,850

104 HUNT CONSLD INC HUNT REFINING CO Alabama TUSCALOOSA 36,000

105 SUNCOR ENERGY INC SUNCOR ENERGY (USA) INC Colorado COMMERCE CITY 

EAST 35,000

106 MURPHY OIL CORP MURPHY OIL USA INC Wisconsin SUPERIOR 34,300

107 NUSTAR ENERGY LP NUSTAR ASPHALT REFINING LLC New Jersey PAULSBORO 32,000

108 ALON ISRAEL OIL COMPANY 

LTD EDGINGTON OIL CO INC California LONG BEACH 31,500

109 FLYING J INC BIG WEST OIL CO Utah NORTH SALT 

LAKE 29,400

110 NUSTAR ENERGY LP NUSTAR ASPHALT REFINING LLC Georgia SAVANNAH 28,000

111 COUNTRYMARK COOP INC COUNTRYMARK COOPERATIVE INC Indiana MOUNT VERNON 26,500

112 KERN OIL & REFINING CO KERN OIL & REFINING CO California BAKERSFIELD 26,000

113 HOLLY CORP HOLLY REFINING & MARKETING CO Utah WOODS CROSS 25,050

114 SINCLAIR OIL CORP LITTLE AMERICA REFINING CO Wyoming EVANSVILLE 24,500
Final Staff Report – Part 1 Appendix F – U.S. Refineries Operable Capacities

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 270 November 2, 2010 

115 ERGON INC ERGON REFINING INC Mississippi VICKSBURG 23,000

116 WESTERN REFINING INC. WESTERN REFINING SOUTHWEST INC New Mexico GALLUP 20,800

117 ERGON INC ERGON WEST VIRGINIA INC West 

Virginia NEWELL 20,000

118 ARCTIC SLOPE REGIONAL CORP PETRO STAR INC Alaska NORTH POLE 19,700

119 WESTERN REFINING INC. WESTERN REFINING SOUTHWEST INC New Mexico BLOOMFIELD 16,800

120 CONOCOPHILLIPS CONOCOPHILLIPS ALASKA INC Alaska PRUDHOE BAY 15,000

121 SAN JOAQUIN REFINING CO INC SAN JOAQUIN REFINING CO INC California BAKERSFIELD 15,000

122 AGE REFINING & MARKETING 

INC AGE REFINING INC Texas SAN ANTONIO 14,021

123 WYOMING REFINING CO WYOMING REFINING CO Wyoming NEW CASTLE 14,000

124 CALUMET LUBRICANTS CO CALUMET LUBRICANTS CO LP Louisiana COTTON VALLEY 13,020

125 BP PLC BP EXPLORATION ALASKA INC Alaska PRUDHOE BAY 12,780

126 VENTURA REFINING AND 

TRANSMISSION LLC VENTURA REFINING & TRANSMISSION LLC Oklahoma THOMAS 12,000

127 HUNT CONSLD INC HUNT SOUTHLAND REFINING CO Mississippi SANDERSVILLE 11,000

128 SILVER EAGLE REFINING INC Silver Eagle Refining Utah WOODS CROSS 10,250

129 AMERICAN REFINING GROUP 

INC AMERICAN REFINING GROUP INC Pennsylvania BRADFORD 10,000

130 CONNACHER OIL & GAS LTD MONTANA REFINING CO Montana GREAT FALLS 10,000

131 GREKA ENERGY Greka Energy California SANTA MARIA 9,500

132 WORLD OIL CO LUNDAY THAGARD CO California SOUTH GATE 8,500

133 CALUMET LUBRICANTS CO CALUMET LUBRICANTS CO LP Louisiana PRINCETON 8,300

134 MARTIN RESOURCE 

MANAGEMENT GRP MARTIN MIDSTREAM PARTNERS LP Arkansas SMACKOVER 7,500

135 VALERO ENERGY CORP VALERO REFINING CO CALIFORNIA California WILMINGTON 

ASPHALT PLANT 6,300

136 MIDSOUTH ENERGY LLC SOMERSET ENERGY REFINING LLC Kentucky SOMERSET 5,500

137 GOODWAY REFINING LLC GOODWAY REFINING LLC Alabama ATMORE 4,100

138 GARCO ENERGY LLC GARCO ENERGY LLC Wyoming DOUGLAS 3,600

139 SILVER EAGLE REFINING INC Silver Eagle Refining Wyoming EVANSTON 3,000

140 OIL HOLDING INC TENBY INC California OXNARD 2,800

141 FORELAND REFINING CORP FORELAND REFINING CORP Nevada ELY 2,000

*Only Refineries with Atmospheric Crude Oil Distillation Capacity. 

Source: Refinery Capacity Data by individual refinery as of January 1, 2010 
Final Staff Report – Part 1 Appendix F – U.S. Refineries Operable Capacities

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 271 November 2, 2010 

Appendix G – FCCU Capacity of California Refineries 

Reference: U.S. Energy Information Administration “Capacity of Operable Petroleum Refineries by 

State as of January 1, 2010” 

CORPORATION COMPANY_NAME SITE PRODUCT

QUANTITY 

(Barrels Per 

Calendar Day)

BP PLC BP WEST COAST PRODUCTS LLC LOS ANGELES CAT CRACKING: FRESH FEED 101,500

EXXON MOBIL CORP EXXONMOBIL REFINING & SUPPLY CO TORRANCE CAT CRACKING: FRESH FEED 83,500

CHEVRON CORP CHEVRON USA INC RICHMOND CAT CRACKING: FRESH FEED 80,000

VALERO ENERGY CORP VALERO REFINING CO CALIFORNIA BENICIA CAT CRACKING: FRESH FEED 72,000

TESORO CORP TESORO REFINING & MARKETING CO MARTINEZ CAT CRACKING: FRESH FEED 68,000

CHEVRON CORP CHEVRON USA INC EL SEGUNDO CAT CRACKING: FRESH FEED 66,500

ROYAL DUTCH/SHELL GROUP SHELL OIL PRODUCTS US MARTINEZ CAT CRACKING: FRESH FEED 61,800

VALERO ENERGY CORP VALERO REFINING CO CALIFORNIA WILMINGTON REFINERY CAT CRACKING: FRESH FEED 52,200

CONOCOPHILLIPS CONOCOPHILLIPS COMPANY WILMINGTON CAT CRACKING: FRESH FEED 48,700

TESORO CORP TESORO REFINING & MARKETING CO WILMINGTON CAT CRACKING: FRESH FEED 31,958
Final Staff Report – Part 1 Appendix H – List of World’s Largest Corporations

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 272 November 2, 2010 

Appendix H – List of World’s Largest Corporations 

Reference: Fortune Global 500, Fortune Magazine, July 26, 2010 

Rank 

2009 

Rank 

2008 

Corporation Country Revenues 

($ millions) 

% change 

from 2008 

1 3 Wal-Mart Stores U.S. 408,214.0 +0.6 

2 1 Royal Dutch Shell Netherlands 285,129.0 -39.5 

3 2 ExxonMobil U.S. 284,650.0 -35.7 

4 4 BP Britain 246,138.0 -32.9 

5 1 Toyota Motor Japan 204,106.1 -0.1 

6 11 Japan Post Holdings Japan 202,196.1 +1.8 

7 9 Sinopec China 187,517.7 -9.8 

8 15 Stategrid China 184,495.8 +12.4 

9 73 AXA France 175,257.4 +118.4 

10 13 China National Petroleum China 165,496.5 -8.6 

11 5 Chevron U.S. 163,527.0 -37.9 

12 8 Ing Group Netherlands 163,203.8 -28.0 

13 12 General Electric U.S. 156,779.0 -14.4 

14 6 Total France 155,887.1 -33.6 

15 37 Bank of America Corp. U.S. 150,450.0 +33.0 

16 14 Volkswagen Germany 146,204.7 -12.2 

17 7 ConocoPhillips U.S. 139,515.0 -39.5 

18 24 BNP Paribas France 130,708.1 -4.0 

19 47 Assicurazioni Generali Italy 126,012.5 +22.2 

20 20 Allianz Germany 125,999.0 -11.5 

The top 20 corporations are listed in the table above. The table above contains information listed in 

the list of “Fortune Global 500”, Fortune magazine, dated July 26, 2010. As explained in the 

Fortune magazine, Fortune Global 500 ranks 500 corporations that have the largest revenues in the 

world, in descending order, according to their total revenues for their respective fiscal years ended 

on or before March 31, 2010. All companies on the list of Fortune Global 500 must publish 

financial data and report part or all of their figures to a government agency. Figures in the lists are 

as reported, and comparisons are with the prior year’s figures as originally reported for that year. 

The list shows that general global economy is down for almost all corporations in 2008-2009. 

However, several of the corporations such as ExxonMobil, BP, Chevron, and ConocoPhillips still 

remain as the top 20 richest corporations in the world. 
Final Staff Report – Part 1 Appendix I – Projected 2019 Emissions & Growth Factors

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 273 November 2, 2010 

Appendix I – Projected 2019 Emissions & Growth Factors 

(Authors: Susan Yan, Kathy Hsiao, and Ali Ghasemi) 

2019 RECLAIM SOx Baseline Emissions and Reductions Calculation 

The AQMD’s Annual Emission Reports (AER) team used the FY97-98 audited and revised SOx 

emissions provided by the AQMD’s RECLAIM Engineering & Compliance team on February 23, 

2010 as the base. The AQMD’s AER team refined and distributed the audited data by rule, by 

facility and by equipment types. The distributed 97-98 SOx baseline emissions with a total of 19.48 

tons per day are then grown to 2019. Staff used composite growth factors from 2002 to 1997 and 

forecast growth factors from 2002 to 2019 of the 2007 AQMP to project SOx emissions in 2019. 

There were two existing SOx rules, R431.1 and R431.2, and seven new rules impacting the SOx 

universe. For this analysis, there should be no overlapping controls among rules. Therefore, 

overlapping controls from R431.1 & R431.2 are being overridden by the new rules. Sources not 

impacted by the new rules reflect controls from R431.1 & 431.2 when appropriate. The seven new 

rules with 2019 control factors impacting the SOx universe are: 

Rule# Description 2019 Control Factor* 

R468 Sulfur Recovery Units (SRUs) 0.63 

R469 Sulfuric Acid Units 0.04 

R1105.1 FCCU 0.06 

R1109 Refineries Boilers & Heathers 0.20 

R1117 Glass Melting Furnace 0.01 

R1119 Coke Calciner 0.05 

R1156 Portland Cement Mfg 0.74 

*Draft Staff Report, page I-95 to I-99, Agenda#27 of 1/8/10 Board meeting. 

The 2019 growth only emissions and the 2019 remaining SOx emissions are calculated to reflect 

controls from all rules. The 2019 SOx baseline with growth only, reductions and remaining 

emissions by rule are listed below: 

Number Description 

97-98 

Audited 

Emissions

2019 

Growth only 

Emissions

Reductions 

from Rules 

2019 

Remaining 

Emissions

R468 Sulfur Recovery Units 2.03 2.03 0.75 1.28

R469 Sulfuric Acid Units 1.06 1.37 1.31 0.05

R1105.1 FCCU 5.68 5.68 5.34 0.34

R1109 Refineries Boilers & Heaters 6.11 6.11 4.88 1.22

R1117 Glass Melting Furnaces 1.71 2.48 2.45 0.02

R1119 Coke Calciner 1.31 1.31 1.25 0.07

R1156 Portland Cement Mfg 0.53 1.36 0.35 1.01

R431.1&2 Others 1.06 1.18 0.05 1.12

 Total (tons per day) 19.48 21.51 16.40 5.12
Final Staff Report – Part 1 Appendix I – Projected 2019 Emissions & Growth Factors

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Proposed Amended Regulation XX Part I - 274 November 2, 2010 

The above resulting table with more details is sent to the Rule Staff for further analysis. 

Composite Growth Factors (2005-2019) 

Rule Staff requested 2005-2019 composite growth factors for R469 (Sulfuric Acid Units), R1117 

(Glass Melting Furnace) and R1156 (Cement Mfg.). Using growth factors in the 2007AQMP by 

county and by facility, the FY97-98 audited SOx values provided by the RECLAIM group are 

projected to 2005 and 2019. The projected emissions are then grouped by rule by facility. To 

calculate the composite growth factors from 2005 to 2019 by rule, staff divides sum of 2019 growthonly emissions by sum of 2005 growth-only emissions for each rule.
Final Staff Report – Part 1 Appendix J – Socioeconomic Analysis

_________________________________________________________________________________________________ 

Proposed Amended Regulation XX Part I - 275 November 2, 2010 

Appendix J – Socioeconomic Analysis 

(Author: Shah Dabirian. The Socioeconomic Analysis is a stand-alone document attached by 

reference.) 

- End of Document -