# 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 De puty 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 includ e this minor change.

### Acknowledgements

The author would like to thank the following AQMD’s staff members fo r 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 SUMM ARY

............................................................................................................. ........................... 1

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

1.1 L EGISLATIVE A UTHORITY ............................................................................................................................ 19

1.2 F INE P ARTICLE R EGULATION AND SO X C ONTROL ....................................................................................... 19

1.3 C URRENT RECLAIM P ROGRAM ................................................................................................................. 20

1.4 C ONTROL M EASURE CMB-02 ..................................................................................................................... 21

1.5 A FFECTED F ACILITIES

.............................................................................................................................. .... 21

1.6 2007 A IR Q UALITY M ANAGEMENT P LAN ................................................................................................... 22

1.7 2005 A NNUAL E MISSIONS R EPORT .............................................................................................................. 24

CHAPTER 2 – BEST AVAILABLE RETR OFIT CONTROL TECHNOLOG Y............................................... 26

2.1 D EFINITION

.............................................................................................................................. .................... 26

2.2 BARCT E VALUATION P ROCESS .................................................................................................................. 26

2.2.1 Identify Technology That Can Achi eve Maximum Degree of Reduction ............................................. 26

2.2.2 Evaluate Control Effecti veness ................................................................................................ ........... 28

2.2.3 Conduct Top-Down Cost E ffectiveness Analysis ................................................................................. 28

2.2.4 Select Best Available Retrofit Control Technolo gy (BARCT) ............................................................. 29

CHAPTER 3 – FLUID CATALYT IC CRACKING UNITS ................................................................................. 31

3.1 P ROCESS D ESCRIPTION

.............................................................................................................................. .. 31

3.2 C URRENT A LLOCATIONS AND E MISSIONS .................................................................................................... 32

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

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

3.3 C ONTROL T ECHNOLOGY

.............................................................................................................................. 34

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

3.3.2 Wet Gas Sc rubbers ............................................................................................................. ................. 38

3.4 A CHIEVED -I N -P RACTICE I NFORMATION ...................................................................................................... 43

3.5 P ROPOSED BARCT L EVEL AND E MISSION R EDUCTIONS ............................................................................. 45

CHAPTER 4 – REFINERY BO ILERS AND HEATERS ..................................................................................... 47

4.1 P ROCESS D ESCRIPTION

.............................................................................................................................. .. 47

4.2 C URRENT A LLOCATIONS AND E MISSIONS .................................................................................................... 48

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

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

4.3 C ONTROL T ECHNOLOGY

.............................................................................................................................. 49

4.3.1 Lower Sulfu r Fuels ............................................................................................................ .................. 49

4.3.2 Improving Efficiency of Fu el Gas Treatin g System ............................................................................. 50

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

4.4 P ROPOSED BARCT L EVEL AND E MISSION R EDUCTIONS ............................................................................. 53

CHAPTER 5 – SULFUR RECOVE RY – TAIL GAS UNITS .............................................................................. 54

5.1 P ROCESS D ESCRIPTION

.............................................................................................................................. .. 54

5.2 C URRENT A LLOCATIONS AND E MISSIONS .................................................................................................... 56

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

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

5.3 C ONTROL T ECHNOLOGY

.............................................................................................................................. 58

5.3.1 Increase Efficiency of the Sulfur Re covery Unit ............................................................................... .. 58

5.3.2 Increase Efficiency of Tail Ga s Unit .......................................................................................... ......... 59

5.3.3 Wet Gas Sc rubber .............................................................................................................. ................. 61

5.4 P ERFORMANCE I NFORMATION ..................................................................................................................... 64

5.5 BARCT L EVEL AND E MISSION R EDUCTIONS .............................................................................................. 66CHAPTER 6 – SULFURIC ACID MANUFACTURING ..................................................................................... 6 7

6.1 P ROCESS D ESCRIPTION

.............................................................................................................................. .. 67

6.2 C URRENT A LLOCATIONS AND E MISSIONS .................................................................................................... 68

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

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

6.3 C ONTROL T ECHNOLOGY

.............................................................................................................................. 69

6.3.1 EPA BARCT Clea ringhou se ....................................................................................................... ......... 69

6.3.2 Clean Air Act Settleme nts ..................................................................................................... ............... 69

6.4 P ROPOSED BARCT L EVEL AND E MISSION R EDUCTIONS ............................................................................. 71

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

7.1 P ROCESS D ESCRIPTION

.............................................................................................................................. .. 73

7.2 C URRENT A LLOCATIONS AND E MISSIONS .................................................................................................... 74

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

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

7.3 C ONTROL T ECHNOLOGY

.............................................................................................................................. 75

7.4 BARCT L EVEL AND E MISSION R EDUCTIONS .............................................................................................. 76

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

8.1 P ROCESS D ESCRIPTION

.............................................................................................................................. .. 78

8.2 C URRENT A LLOCATIONS AND E MISSIONS .................................................................................................... 79

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

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

8.3 C ONTROL T ECHNOLOGY

.............................................................................................................................. 80

8.3.1 Dry Scrubber at BP Wilmi ngton ................................................................................................. ........ 80

8.3.2 Wet Scrubber and Wet ESP at BP Cherry Poin t Refinery ................................................................... 81

8.4 BARCT L EVEL AND E MISSION R EDUCTIONS .............................................................................................. 82

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

9.1 P ROCESS D ESCRIPTION

.............................................................................................................................. .. 84

9.2 C URRENT A LLOCATIONS AND E MISSIONS .................................................................................................... 86

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

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

9.3 C ONTROL T ECHNOLOGY FOR C OAL -F IRED F LUIDIZED -B ED B OILERS ......................................................... 87

9.3.1 In-Process Contro l Technology ................................................................................................. ......... 87

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

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

9.4 C ONTROL T ECHNOLOGY FOR C EMENT K ILNS .............................................................................................. 89

9.4.1 Fuel Sw itchi ng................................................................................................................. .................... 89

9.4.2 Process Co ntrol................................................................................................................ ................... 89

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

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

9.4.5 Costs and Co st Effec tiveness ........................................................................................... .......................... 90

9.5 BARCT L EVEL AND E MISSION R EDUCTIONS .............................................................................................. 91

CHAPTER 10 – CONTINUOUS EMISSI ONS MONITORING SYSTEM ........................................................ 93

10.1 D ILUTION -E XTRACTIVE

.............................................................................................................................. . 93

10.2 E XTRACTIVE N ON -D ILUTION ....................................................................................................................... 94

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

11.1 D ISTRICT ’ S S URVEY

.............................................................................................................................. ...... 97

11.1.1 Wa ter Demand ......................................................................................................... .............................. 97

11.1.2 Wa stewater ........................................................................................................... .................................. 98

11.2 C ALIFORNIA W ATER P LAN ........................................................................................................................ 105

11.3 20 X 2020 W ATER C ONSERVATION P LAN .................................................................................................... 108

11.4 U RBAN W ATER M ANAGEMENT P LANS .......................................................................................................... 113

11.5 C ONCLUSION

.............................................................................................................................. ............... 121

CHAPTER 12 – COSTS & COST E FFECTIVENESS ANALYSIS .................................................................. 12312.1 S CENARIO A NALYSIS

.............................................................................................................................. ... 123

12.2 C OST -E FFECTIVENESS A NALYSIS U SING NEC’ S E STIMATES ..................................................................... 130

12.3 C OMPARISON OF C OSTS AND C OST -E FFECTIVENESS .................................................................................. 133

12.4 C OST E FFECTIVENESS FOR S CENARIO 4 AND S CENARIO 5 ......................................................................... 134

12.5 I NCREMENTAL C OST E FFECTIVENESS ........................................................................................................ 136

12.6 C OMPARISON OF C OST E FFECTIVENESS TO O THER R ULES A DOPTED BY THE G OVERNING B OARD ............ 136

CHAPTER 13 – RTC REDUCTIONS & IMPLEMENTA TION ....................................................................... 138

13.1 RTC R EDUCTIONS E STIMATED FROM 1997 B ASELINE ............................................................................... 138

13.2 A LTERNATIVE S HAVE

.............................................................................................................................. .. 141

13.3 RTC R EDUCTIONS E STIMATED FROM 2005 B ASELINE ............................................................................... 141

CHAPTER 14 – COMMEN TS & RESPONSES ............................................................................................. ..... 145

R ESPONSES TO WSPA’ S C OMMENTS R ECEIVED IN R EFINERY C OMMITTEE M EETING ON O CTOBER 14, 2010 ....... 145

R ESPONSES TO INTERCAT’ S C OMMENTS R ECEIVED ON O CTOBER 10, 2010 ....................................................... 147

R ESPONSES TO O WENS -B ROCKWAY ’ S C OMMENTS R ECEIVED ON O CTOBER 21, 2010 ........................................... 153

R ESPONSES TO O WENS -B ROCKWAY ’ S C OMMENTS R ECEIVED ON S EPTEMBER 22, 2010 ....................................... 157

R ESPONSES TO WSPA’ S C OMMENTS R ECEIVED FROM M ARCH 2010 TO A UGUST 2010 ........................................ 178

R ESPONSES TO WSPA’ S C OMMENTS R ECEIVED ON J ULY 14, 2009 ....................................................................... 187

R ESPONSES TO C HEVRON ’ S C OMMENTS R ECEIVED ON J ULY 14, 2009 .................................................................. 201

R ESPONSES TO T ESORO ’ S C OMMENTS R ECEIVED ON J ULY 14, 2009 ..................................................................... 205

R ESPONSES TO BP’ S C OMMENTS R ECEIVED ON J ULY 14, 2009 ............................................................................. 208

R ESPONSES TO P ARAMOUNT ’ S C OMMENTS R ECEIVED ON J ULY 14, 2009 .............................................................. 208

R ESPONSES TO WSPA’ S C OMMENTS R ECEIVED ON J ULY 2, 2008 ......................................................................... 210

R ESPONSES TO BP’ S C OMMENTS R ECEIVED J ULY 1 ST

, 2008 .................................................................................. 214

R ESPONSES TO V ALERO ’ S C OMMENTS R ECEIVED J ULY 1 ST

, 2008 .......................................................................... 218

R ESPONSES TO R HODIA ’ S C OMMENTS R ECEIVED A PRIL 29 TH

, 2008 ...................................................................... 220

R ESPONSES TO R HODIA ’ S C OMMENTS R ECEIVED N OVEMBER 25 TH

, 2008 ............................................................ 220

R ESPONSES TO WSPA’ S C OMMENTS R ECEIVED A PRIL 29 TH

, 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 CAPA CITIES ...................................................................... 267

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

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

APPENDIX I – PROJECTED 2019 EMIS SIONS & GROWTH FACTORS ................................................... 273

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

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

## Executive Summary

RECLAIM Program & Best Availabl e 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 st ationary 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 s ources located at RECLAIM facilities. The RECLAIM program started with 41 SOx facilities and 392 NOx fac ilities. By the end of 2005 compliance year, the program incl uded 33 SOx facilities and 304 NOx facilities. By the end of 2008, the SOx facilities redu ced to 32 facilities.

Under the SOx RECLAIM program, the RECLAIM f acilities are issued SOx annual allocations (also known as facility caps), which decline a nnually 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 T echnology (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, th e facilities have the flexibility to install air pollution control equipment, change method of operations, or purchase RECLAIM Trading Credits (RTC s) to meet the BARCT levels.

AQMD staff is proposing amendments to Regu lation 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 Californi a Health and Safety (H&S) Code §40440, which is applicable to mark et-based incentive programs, as well as equivalency to command-and-co ntrol regulations, as required under H&S Code § 39616(c)(1). Reductions in SOx will help the Basin attain the federal annual aver age 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 m eet the fine particulate (PM 2.5 ) standards by 2010. The Clean Air Fine Particle Implementation Rule requires the District to achiev e the fine partic ulate standards as expeditiously as possible, and allows the Dist rict 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 PM 2.5 emissions, as well as the emissions from PM 2.5 precursors, specifically sulfur dioxide (SO 2 ), and the most potent PM 2.5 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 ru le, 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 th e PM2.5 standards by 2014 and also stated that staff may need to incorporate the concept of facility modernization as desc ribed under Control Measure MCS01 - Facility Modernization to achieve additional reducti ons 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 to ns per day of SOx allocations for the 2003 compliance year and beyond for the f acilities in SOx RECLAIM. Th is 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 to tal 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 responsibl e 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 t ons per day in 2005 and are the focus for BARCT evaluations in this proposed rule amendm ent. 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 presen ts the 2005 emissions distribution, and Figure EX-2 presents a comparison for RTC Holdings and emissions between th e top 11 facilities and the remaining 21 active faciliti es 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 Hold ings 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 0.73Final 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 summari zed in Table EX-1. In 2008, staff formed the RECLAIM Working Group that included members representing SOx RECL AIM facilities, the

Western States Petroleum Asso ciation (WSPA), the environmen tal community, as well as

CARB and U.S. EPA to discuss and brainsto rm the proposed amended SOx RECLAIM. The first meeting was conducted on February 7, 2008.

On April 3, 2008, staff released the first Prelim inary Draft Staff Report, and conducted two Working Group meetings on April 3 and April 30, 2008 to discuss sta ff’s initial proposal including allocations, emissions inventory and distribution, and potential BARCT for seven (7) major emitting categories of stationary source eq uipment located at the eleven (11) major SOx

RECLAIM facilities.

In May 2008, staff, WSPA and the refineries work ed in collaboration to develop a Request for Proposal (RFP) to solicit expert consultants to conduct independent studies on feasibility and

cost effectiveness. Additiona l 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 c onducted a Bidder’s C onference immediately after. A public notice advertising the RFP and inviting bi ds was published in accordance with AQMD’s Procurement Policy and Procedure. The Distri ct’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; on e AQMD Program Supervisor of the Refinery Team; and one representative from WSPA. St aff invited one representative from the environmental group and two representatives fro m the U.S. EPA; however, they could not participate in this evaluation pr ocess due to schedule conflicts.

The panel was in agreement that the contr actors possessed good qualifi cations, presented good approaches and had workable schedules. Af ter serious considerati on, 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 a nd 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 immediatel y after receiving the awards. First, the consultants and staff scheduled and conducte d site visits at BP, Chevron, ConocoPhillips, Tesoro, Valero, ExxonMobil, California Portland Cement, Owens Brockway, and Rhodia in September and Octo ber 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 fa cilities, observed the physical layout of theFinal 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 cons traints provided by the refinery technical experts related to future prospective add-on control devices.

After the site visits, the consultants conducted their own independent re search, contacted the control manufacturers and vendors, gathered cost information, and performed their own independent engineering analyses on commercial ly available control t echnologies and cost effectiveness. In October 2008, the consulta nts developed the draft reports which were distributed to the affected facilities and AQM D 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 kiln s, coal fired boiler, gl ass furnaces, and sulfuric acid plants on December 16, 2008 as planned in the contracts.

Because of the complexity associated with the re finery 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 refi neries in January and February 2009. The consultants’ dr aft 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 s ubcontractor, AEC Engineering, a ddressed substantial amount of comments received from all six refineries, revised their reports appropriately, and finalized their assessment for the refineries in April 2009. Th e non-confidential reports from NEXIDEA, ETS and AEC Engineering are available for public information.

In 2009, staff reconvened the Working Group mee tings. A Public Workshop was conducted on June 23, 2009, and in this works hop, staff released 1) the Draf t Staff Report to discuss BARCT, cost effectiveness, RTC reduction met hodology, 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 re quested. Two Working Group meetings were held on August 27 and December 15, 2009.

At the January 8, 2010 Governing Board Meeting, st aff 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 Gove rning Board approved in January 2010 the hiring of a second consultant to provide an independent review of the analys es previously conducted. To fulfill that commitment, staff hi red 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 revi ew 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 CE QA document concurrently with the second Refinery Committee Meeting ad dressing SOx RECLAIM. Staff also conducted a Public Working Group Meeting and a Public Consulta tion Meeting on September 8, 2010. Staff’s

revised estimates for BARCT reductions at th is time were 5.4 tpd emission reductions from 2005 baseline, 6.1 tpd RTC reductions from 2012 – 2019 amounting to a 55% RTC shave. TheFinal 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, severa l significant changes have been made as follows: 1) exclusion of emission reductions of 0.85 tpd estimated fr om boilers/heaters si nce the proposed BARCT limit was unchanged from the previous BARCT le vel of 40 ppmv; 2) use of audited emissions in the analysis for RTC shave, and 3) extens ion 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 th e 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 Wo rking Group was formed
February 07, 2008 Public Consu ltation Meeting was conducted

April 03, 2008 April 30, 2008 Preliminary Draft Staff Report wa s released. Two Working Group Meetings were conducted.

May 1, May 15, May 28, June 20,

July 02, 2008 Request for Proposal to seek expe rt 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 Go verning 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 eval uate the six proposals received & make recommendation to the Governing Board
September 5, 2008 Staff presented the r ecommendation 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 facili ties and conducted their feasibility and cost analyses, and the draft analyses were released to the

facilities for comments.

December 16, 2008 NEXIDEA finali zed 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 s econd 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 Works hop and CEQA Scoping Meeting. At this stage, staff proposed a bout 7 tpd RTC reduction from 2012- 2017 with a total costs (present wo rth 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 conducte d in 2009. In addition, from March – Decemb er, staff conducted several meetings with WSPA and the refineri es 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 Co mmittee Meeting on December 11 and a WGM on December 15. At this stage, staff’s estimates were 6.2 tpd emission reductions fr om 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 “Informa l tional 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 Engineer ing Inc. (NEC) to review ETS, Inc. and NEXIDEA’s feasibility an d costs analyses. NEC and staff

visited the refineries in Marc h/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 wa ter usage in California.
August 18, 2010 Draft CEQA document was rele ased and staff conducted a second Refinery Committee Meeting. Sta ff’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 reducti ons 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 & c onducted 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 1 s t , 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 th e RTC reduction methodology first developed in

the 2005 NOx RECLAIM rule amendment. In th is 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 appl ied 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 acc ount for inaccessible RTCs due to imperfect market conditions and RTCs held by facilities to ensure complian ce with annual audits. The proposed project results in 5.4 tons per day emi ssion reductions from the 2005 baseline. This is equivalent to 6.1 tons per day RTC reduction, approximately 55% re ductions of RTC’s holdi ngs of 11.09 tons per day by 2019. 1

In staff’s current proposal shown in Tabl e 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 cons idered 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 re ported 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 adjustment s to reflect the extension period.

1 Based on RTC records as of August 29, 2009Final 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 eff ectiveness for each of the seven (7) categories of

sources located at the elev en (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 e ffectiveness 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 es timated to be $630 million - 745 million dollars. The weighted average cost effectiveness was about $16 K - $19K per to n 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 pr esents the estimated costs (the present worthFinal 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 reduc tions would be implemente d over eight (8)years:

⎯ 1.5 tons per day of reducti ons in compliance year 2012

⎯ 1.5 tons per day of reducti ons in compliance year 2013

⎯ 1.5 tons per day of reducti ons in compliance year 2014

⎯ 0.32 tons per day of reducti ons in compliance year 2015

⎯ 0.32 tons per day of reducti ons in compliance year 2016

⎯ 0.32 tons per day of reducti ons in compliance year 2017

⎯ 0.32 tons per day of reducti ons in compliance year 2018

⎯ 0.32 tons per day of reducti ons 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 sta ndard in 2015. The remain ing 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 Cos t-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 propos ed 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 realis tic emission reduction

scenarios that use cost effectiv eness 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 assu med that RECLAIM facilities would implement voluntarily the cost-effective control measures id entified 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 comp rised of unused RTCs (2.55 tpd) in the market, early reductions achieved at two refineri es (1 tpd), and reduc tions from currently not operative cement kilns (0.25 tpd), the RECLAI M facilities will be in compliance with the proposed shave in 2014 without si gnificant expenditure s on BARCT for major equipment such as FCCUs and SRU/TGs. Implementing BARC T for FCCUs and SRU/TGs will likely take place after 2014 to meet the target of 2019. Ho wever, careful evaluation of the second dashed line in Figure EX-5 intersects with Curve 2 sugge sts 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 ru le amendment was released on August 18, 2010. The draft socioeconomic analysis was released w ith this revised draft st aff report. The draft rule language for the proposed Rule 2002 is attached with this revised draf t 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 2020ProjectedRTC&EmissionReductions

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 ce ment 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 refine ries $2.85 billion to comply with 60% shave. WSPA hired a consultant firm (ENVIRON) to co llect data from the refineries and perform analysis with the results aggr egated 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’ estimate s. If the costs for thes e 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 pr esented at the September 22 Refinery Committee Meeting.

On October 12, 2010, WSPA revised its cost analys is to reflect staff’s proposal of 55% shave. The overall costs estimated by WSPA were now $1.637 billion. WSPA indi cated that it would cost $836 million to comply with BARCT. WSPA also indicate d that complyin g with BARCT would not be enough; WSPA’s members asserted that they would need to in vest 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 consulta nts estimated that the refineries would reduce 3.92 tpd by installing 4 WGSs fo r the FCCUs, 3 WGSs for th e SRU/TGs, 1 WGS for coke calciner and implementing other proc ess modification at a cost (pre sent worth value for 25 years) of between $561 million - $638 million and the co st-effectiveness of $16K - $18K per ton.

In comparison, as shown in Table EX-3, WSPA es timated that the refineries would reduce 3.81 tpd by 1) installing 2 WGSs fo r 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 va lue 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 WS PA’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 eac h member facility rather than relying on RTCs available in the open market to meet staff’s pr oposed shave of 55%. However, the first two of the “other” strategies proposed by WSPA and its members in Tabl e 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 f ourth 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 refineri es have demonstrated that they can achieve 5.31 tpd re ductions with the main strategy and the two “other” (third and fourth) cost-effective strategies negating th e 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 re ductions that can be ob tained 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 reduc tions to comply with the 55% sh ave of 5.17 tpd re duction 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 $22K 389 FCCU 4 WGS 328

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 & CostsFinal Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 15 November 2, 2010 Key Issues Raised Prior to the Informa tional Hearing on January 8, 2010

There are four (4) key issues ra ised by the stakeholde rs: 1) BARCT determination, 2) water and wastewater, 3) market viability, 4) shaving met hodology for facilities that are not subject to new BARCT, and for facilities that ar e subject to new BARCT. Staff’ s responses to these key issues

are summarized below:

1) BARCT Determination
Stakeholders commented that st aff should pursue only 3 tons per day reduction as stated in the 2007 AQMP to meet the SIP commitment. The cu rrent 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-es timated 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 otherw ise be developed as a result of BARCT

reassessment:

“...achieve an equivalent or gr eater level of emission reduc tions at an equivalent or

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

The percent RTC reduction (55%) that staff esti mated 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, ceme nt 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 indica ted that in the South Coast Air Basin 25% of the ambient

PM2.5 is attributed to contribution from sulf ates. 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 fede ral 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 incl uded 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 cont rol strategies committed in the 2007 AQMP for meeting the 2015 annual PM2.5 standard are necessa ry 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 part s 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 analys es, 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 SOxFinal Staff Report – Part 1 Executive Summary

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 16 November 2, 2010 reduced) from staff proposal. While these refi nements 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 th e 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 reductio ns by 2014). The remaining reductions will be

submitted later.

2) Water & Wastewater Impacts
Stakeholders commented that the water and wa stewater impacts of the project would be significant.

Staff’s Response: Industry argues that staff proposal will result in sign ificant increases on water demand and wastewater impacts due to the water-intensive operation of wet gas scrubbers. To the extent that wet gas scrubbe rs are used to comply with the proposed SOx control requirements of the propos ed project, staff ac knowledges that the to tal 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 f acilities is well below th e SCAQMD’s significance threshold of 5 million gallons per day of total increased water demand (i.e. potable water, recycled water, and groundwater). The informa tion that staff received to date from the water purveyors and collected from their 2005 Urban Wa ter 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 wate r supplies to meet increased water demand is another water demand signifi cance threshold crite rion. Even though the potential increase in total water demand is below the SCAQMD’s significance threshold of 5 million gall ons per day, and because California is in a state of emergency for drought, staff has identified another cr iterion for what would be

considered a substantial use of when determin ing 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 dema nd project, the potable water de mand of the proposed project would exceed the more stringent criterion if recycl ed water was not utilize d. Currently, recycled

water is used at the three refineries in the basi n and the water purveyors indicated that, as part of their Urban Water Management Plans, they are in the process of expandi ng 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 wastew ater treatment capacity to trea t the increase in wastewater generated. An increase of 25 pe rcent would trigger a permit revi sion 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 th e 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 en ough 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 reassessmen t and demonstrate equivalency with commandand-control rules which would otherwise be devel oped 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 ad dition, 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 subm it 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 pr ovides the facilities more operational flexibilities than being subj ect to stringent requirements in command-andcontrol rules and regulations.

4) Shaving Methodology Facilities with no equipment subject to new BA RCT commented that the uniform shave was not equitable, would create significant difficulties for th em to stay in compliance, and indicated that they had limited ability to buy RTCs from large f acilities. While WSPA and the refineries that are subject to new BARCT ar gued strongly during the rule development process in 2008-2009

for the use of a shave methodol ogy that was consistent with that used during the 2005 NOx RECLAIM amendment. During the later phas e of the rule develo pment process, they

commented that staff should use the 2005 as baselin e for the shave, not shave the 1.98 tpd RTCs converted from ERCs and portion reserved for Cl ean Fuel projects, and not set new BARCT for

SRU/TGs and cement kilns.

Staff’s Response: Because of the non-uniform emissi ons 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 co mpliance after the shave. To keep the 21 faci lities active in the SOx market, staff is proposing to not shave th e 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 investor s. With this approach, staff estimated that instead of a 52% shave across the board, the 11 faci lities 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 a llocations will be shaved up to the ini tial 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 Augus t 29, 2009 will not sell their RTC holdings to a third party investor or any of the remain ing 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 AQM P, would result in 55% shave to the 11 facilities, including the refi neries and investors, wh ereas 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 ope rations. 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 BARC T 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 inherent ly 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 consul tants’ analyses;

⎯ Method of determining RTC reduc tions and amount estimated;

⎯ Timing of reductions; and

⎯ Preliminary methods of applying reductions.

Draft Staff Report chan ges 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, 201 0, staff modified the document as follows:

⎯ Removed control technology recommendations w ith cost effectivenes s larger than $50 K per ton (1 for FCCU, 2 for SRU/TGTUs, 1 fo r 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) a nd 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 es timated from boilers/heaters since the proposed BARCT limit is retained at th e previous BARCT level of 40 ppmv, and

⎯ Extended the implementation period from 2017 to 2019 and reflected growth embedded in the 2007 AQMP.

Staff wil l continue to revise the draft Staff Report as ne eded 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 in vestors will be shaved at the same ra te 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 Qua lity Management District (AQMD) in 1977 (the Lewis-Presley Air Quality Management Act, Hea lth and Safety Code S ection 40400 et seq.) as the agency responsible for developing and enforc ing air pollution control ru les and regulations in the South Coast Air Basin (Basin). By statute, the AQMD is required to adopt an Air Quality Management Plan (AQMP) demonstrating complia nce 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 a nd regulations that implement the AQMP (H&SC § 40440(a)).

The California Clean Air Act (CCAA) also requi res 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 Technologi es (BARCT) for existi ng 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 Regu lation and SOx Control

Scientific studies have found an associatio n between exposure to particulate matter and significant health problems, including: aggrav ated asthma; chronic bronchitis; reduced lung function; irregular heartbeat; hear t attack; and premature death in people with heart or lung disease. Individuals particularly sensitive to fi ne particle exposure include older adults, people with heart and lung disease, and children.

In July 1997, the U.S. EPA promulgated the Nati onal Ambient Air Quality Standards for Fine Particles (PM-2.5). The annual standard is a level of 15 micrograms per cubic meter ( μ g/m3) based on a 3-year average of a nnual mean PM2.5 concentrations. Th e 24-hour standard is a level

of 65 μ g/m3, based on a 3-year average of the 98th percentile of 24-hour c oncentrations. In September 2006, EPA significantly stre ngthened the previous daily fine particle standard from

65 μ g/m3 to 35 μ g/m3. This standard increases protection of the public from short-term exposure to fine particles.

There are multiple areas across the countr y exceeding the federal PM2.5 standards. Unfortunately, Southern Californi ans are burdened with a disp roportional 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 deve lop an Air Quality Management Plan by 2008 to address the implementation processes to substant ially reduce PM2.5 in or der to meet the PM2.5 standards by 2010. The attainment date of 2010 ma y 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 th e region’s attainment demonstration to the

federal ozone and PM2.5 standards and includes a fo rmal 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, ammoni a and volatile organic compounds. The effect of reducing emissions of each of these pollutant s varies by areas depending on the composition, concentrations of these pollutants and ot her 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 co ntrol technology (RACT) , considering economic and technical feasibility and other factors that are n eeded 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-at tainment areas to evaluate all control measures to reduce direct PM2.5 emissions, as we ll as PM2.5 precursors, especially SOx. While the 2007 AQMP lays out a multi-pollutant control st rategy to demonstrate attainment with the federal PM2.5 standards, it iden tifies 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 Governin g 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, faci lities 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 RECLAI M facilities. To meet the annual declining allocation, RECLAIM facilities have the flexibili ty of installing polluti on control equipment, changing operations, or purchasi ng RECLAIM Trading Credits (RTCs) . It was envisioned that a BARCT analysis be conducted ev ery three years to capture any advancement in control technology and to assure that the RECLAIM program would ach ieve 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, theFinal Staff Report – Part 1 Chapter 1 – Background

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 21 November 2, 2010 RECLAIM rules were amended and the NOx annua l allocations previously given to the NOX RECLAIM facility were further reduced by approximately 20% to reflect BARCT.

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

constant since 2003. The 2003 SOx allocations refl ected the BARCT levels envisioned for SOx in 1993. BARCT analysis for SOx has not been r eevaluated since 1993, and is reevaluated with this proposed amendment.



## 1.4 Control Measure CMB-02

Control Measure CMB-02 estimated that BA RCT would be impleme nted to achieve approximately 3 tons per day SOx emission re ductions from 2011 to 2014. The control measure estimated that reducing sulfur content in refine ry fuel gas could achieve approximately 1.6 tons per day SOx; and reducing SOx emissions from fl uid catalytic cracking units could achieve 1.3 tons per day SOx. It was expected that the cont rol measure implementation may either affect all SOx RECLAIM facilities or only affect the facili ties that have highest SOx emissions and that can employ BARCT. During the rulemaking proce ss, it was envisioned that staff will also explore the feasibility to incorporate the contro l concept of Control Me asure MCS-01 - Facility Modernization to achieve reductions beyond 2014.



## 1.5 Affected Facilities

Currently, there are 32 facilities in the SOx RE CLAIM Program. Six of the 32 facilities are refineries with substantial operational capacitie s compared to 150 refine ries in the U.S, and Chevron and BP are the two largest refineries in the state of Californi a 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 Flui dized Catalytic Cracking Units (FCCU), furnaces, kilns, sulfuric acid plants, tail gas units, boiler s, heaters, internal combustion engines, and gas turbines. The emission inventory of these facili ties and the top emitters at these facilities is discussed in Chapter 1, Section 1.7.

7 Operable capacities of six refineries and their ra nks 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) wa s 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 presen t a sharp distinction be tween the distributions of NOx versus SOx emissions in the basin, a nd explain the importance of undertaking a BARCT

reassessment for RECLAIM facilities in this amen dment of Regulation XX. As shown in Table 1-1 and Figure 1-1, the RECLAIM facilities contribu te 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 contra st, the RECLAIM facilities contri bute 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 faci lities are ranked #2, second only to ships and

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

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 23 November 2, 2010 and ultimately reaching the federal PM2.5 st andards, searching for additional emission reductions in RECLAIM category sour ces becomes an important effort.

FIGURE 1-1
NOx and SOx Emission Di stribution (2002 Baseline)

NOx Emissions RECLAIM
23%

Non-RECLAIM
19% Mobil Sources
58%

SOx Emissions

TABLE 1-2 Top Ten Ranking of SOx Emissi ons 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/Co mmercial 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 sour ces 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 m odeling 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 so urce 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 da y 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 Stat ionary 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 em itting facilities emitted 9.47 tons per day SOx,
which are about 95% of total emissions from RE CLAIM universe. The t op 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 Faci lities (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 LL C,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 RE CLAIM facilities include fluid catalytic cracking units, sulfur r ecovery and tail gas treatment units , refinery boilers and heaters burning refinery gases, coke calciner, cement ki lns, sulfuric acid absorption tower and glass melting furnaces. Staff will focus in reassessing BARCT for these top em itters which emit more
than 80% of SOx emissions at RECLAIM facilities.

TABLE 1-5
Distribution of SOx Emission s 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 complian ce year were the emissions reported from January 1, 2003 – December 31, 2003 fo r Cycle 1 RECLAIM facilities, and from July 1, 2003 – June 31, 2004 for Cycle 2 facil ities. SOx emissions reported for the 2003 calendar year were the emissions reported fr om 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 emissi ons 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) 10.08Final 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 th e 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 Di strict to adopt rules th at requires the use of BARCT for existing sources:

“Require the use of best available contro l technology for new or modified sources and the use of best available retrofit c ontrol 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 RECL AIM 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 emissi on 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 analys is 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-RE CLAIM 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 definiti on 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 reduc tion for this project, staff conducted a thorough and extens ive 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 pot ential future technology) from literature research, consultations with manufacture rs/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, CA RB 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. Sometim es staff is called upon to develop technology forcing rules. In this situation, staff can consid er technology that has not been applied to full scale operations, and provide sufficient time in the rule language to a ssist the technology to reach maturity. In addition, staff can develo p 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 so urce (i.e. has been successfully applied to similar sources with similar gas stream characteristics).

Staff will also consider currently available re trofit control technology, which is a control technology that 1) is being offered commerci ally 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 te chnologies and assess costs and cost effectiveness of control technologies. The c ontractors were required to identify at least two available control technology manufac turers/vendors for each of the seven categories of sources.

The contractors were also aske d 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 revi ew on federal, state or other air po llution control dist ricts’ regulatory requirements is shown in Appendix B of this report. 8

8 In addition, please also see staff’s review of regul atory 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 cont rol technologies were identified, staff evaluated

the control effectiveness of the control technology using the c ontrol efficiency, or the outlet SOx concentration, or the emission factor reporte d for each control technology. These control effectiveness information was obtained by consid ering data available through permitting, source testing, engineering estimates, or performance gu arantees by the contro l manufacturers/vendors.

As part of the contracts, the contractors were re quired to assess the levels of emission reductions
that could be achieved from at least two differe nt types of control t echnology. 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 t op-down cost effectiveness analysis starting with the most effective control technology was conducted to provide information on emission

reductions and cost effectiveness associated wi th different control t echnologies and different

levels of control.

The top-down cost effectiveness an alysis must consider site-speci fic, physical limitation, as well as operational characteristics of the equipment at the facilities. Equipm ent costs, installation costs, annual operating costs, th e useful life of the control equi pment are all captured in this analysis to generate a cost-effectiveness fact or 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 s ubcontractor. Their extensive a nd 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 cost s 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 specifi c 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 effectiv eness 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 rem oved 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 proj ect. 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 dolla rs 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 staf f 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 acc ount of ....economic impacts by each class or category of source.”



## 2.2.4 Select Best Available Retr ofit Control Technology (BARCT)

The H&S Code 40406 requires the District to ta ke into account environmental, energy and economic impacts during the BARCT selection pro cess. The energy impact of each evaluated control technology is the energy penalty or be nefit resulting from the operation of the control technology at the source. An exam ple of the energy impact include s the increase (o r decrease) in energy consumption at the source.

The environmental impacts are evaluated to de termine whether a particular control technology has any impacts, either positiv e or negative, to the envir onment. An example of the environmental impact is the generation of wastewater discharge and solid waste.

The economic impacts (costs and cost effectivene ss) 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 quan tify the environmental effects or impacts (water demand, wastewater treatment, solid waste, en ergy consumption) and pr ovide information on any hazardous materials and hazardous waste, if known for each SOx reduction technique or technology evaluated. The consultant s’ results for this analysis are in their final reports. 10

10 The consultants’ estimates are acc urate except for the reported water demand for the SRU/TG’s wet gas scrubbers. The figures reported in the final report are not th e same as the numbers reported in the draft report. It is an oversight in transferring the numbers, only for th e SRU/TGs. Staff contacted the wet gas scrubberFinal Staff Report – Part 1 Chapter 2 – BARCT Evaluation Process

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 30 November 2, 2010 In addition, the consulta nts were asked to conduct an analysis on concurrent effect on other air pollutants, and made comments and recommendations if there were tec hnologies capable of reducing SOx, and concurrently reducing (or increasing) PM2.5, a nd/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 or ganic compound. Fine particulate impact will be lessened by reducing SO2 emissi ons 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 le vels 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, st aff differed in setting the BARCT limits for glass melting furnace and cem ent kilns/coal-fired boiler, and further

removed the scenarios where the cost effec tiveness was lower exceeding >$50K per ton. The proposed BARCT levels recommended by staff a nd 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 an alyses 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 ope rate six fluid catalytic cracking units (FCCU) in the District: Chevron, BP West Coast, ExxonMobil, ConocoPhill ips, Ultramar and Tesoro. The FCCUs are classified as major sources of emissions in RE CLAIM, 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 barre ls 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 conve rting 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 fluidi zed catalyst is circulated continuously between a reactor and a regenerator and acts as a vehicle to tr ansfer 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 crack ing 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 th e feed and brings it up to the desired reaction temperature. The mixture of catalyst and hydrocar bon vapor travels up the rise r 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 de gree Fahrenheit. As the cracking reaction progresses, the catalyst surface is gradually coated with carbon (coke), re ducing its efficiency. While the cracked hydrocarbon vapors are routed overhead to a distillation column for separation into lighter components, the oi l remaining on the cat alyst is removed by steam stripping before the spent catalyst is cycl ed 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 eith er partially burn the c oke on the catalyst to a

mixture of carbon monoxide (CO) and carbon dioxide (CO 2 ), or completely burn the coke to

CO 2 . The regenerator temperature is carefully controlled to prevent catalyst deactivation by overheating and to provide the desired amount of carbon burn-off. This is done by controlling the air flow to give a desired CO 2 /CO ratio in the exit flue gases or the desired temperature in theFinal Staff Report – Part 1 Chapter 3 – Fluid Catalytic Cracking Units

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 32 November 2, 2010 regenerator. The flue gas containi ng a high level of CO is routed to a su pplemental-fuel fired CO boiler if needed to completely burn off the CO to CO 2 . 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 regene rated catalyst is gene rally 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 th at 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 co ntrol particulate emissions, flue gas from the regenerator is routed through a se ries of cyclones and electrosta tic precipitators. Selective catalytic reduction can be used to reduce nitrogen oxides emi ssions. 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 issu ed emission allocations to their FCCUs based on an emission factor (also known as Tier I emi ssion factor) of 13.7 lbs SOx per thousand barrels refinery feed. The activity of each FCCU used in the allocation determ ination 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 FinesFinal 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 ar e 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 th ere are commercially available technologies that can be used to further reduce SOx em issions from the FCCUs. In addition, the capacity of each FCCU may incr ease 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 sulf ur 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 susc eptible to deactivation. In 1980, it was found that the potential pick-up SO3 in the regenerator wa s 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 hydrotalci te-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 im proved 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. commerci alized 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 reduci ng catalysts remove SOx from the re generator flue gas and release the

sulfur as H 2 S in the FCCU reactor through a three step mechanism:

In the regenerator, sulfur bearing coke is burned to SO 2 ; and in the presence of excess oxygen, a portion of SO 2 is converted to SO 3

S + O 2 → SO 2 SO 2 + 1/2O 2 → SO 3

The magnesium-based reduci ng catalysts “pick-up” SO 3 in the regenerator and form magnesium

sulfate:

M

x O + SO 3 → M

x SO 4

The magnesium sulfate recirculates back to the reactor, and reacts with hy drogen to form either magnesium sulfide and water, or magnesium oxide, and hydrogen sulfide:

M

x SO 4 + 4 H 2 → M

x S + 4H 2 O

M

x S + H 2 O → M

x O+ H 2 S

M

x SO 4 + 4 H 2 → M

x O + H 2 S + 3H 2 O

The H 2 S then exits the FCCU in the dry gas and must be removed by the sulfur recovery units.

This increase in H 2 S, 5% - 20%, can typically be mana ged within a refinery’s operations.



### Performance of SOx Reducing Catalysts

Control efficiency of SOx reducing additives depe nds on many factors such as 1) feed type, 2) starting SOx level, 3) catalyst type, 4) amoun t of catalysts added, and 5) FCCU’s operating

conditions. Manufacturers of SOx reducing catalysts generall y use a proprietary computer model to estimate the performance of their product s. 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 SO x 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, o F 1009 1009 1006 999 1005 1005 985

Reactor O 2 , 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 Flui d 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 develo pment of Rule 1105.1 –

Reduction of PM10 and Ammonia Emissions fr om Fluid Catalytic Cracking Units, five

refineries in the Distri ct experimented with SOx reducing ca talysts 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 PM 10 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 PM 10 (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 PM 10, 41% for SOx 63% for PM 10, 65% for SOx

Note: The percent reduction in total PM10 with the SOx reduci ng 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 emis sions 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 volunt arily conducted a short-term testing with SOx reducing catalysts from September 2008 – Dece mber 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 incr ease in PM10. A considerable amount of SOx reducing additives was needed th roughout this peri od 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 be low was a sustainable level with SOx reducing catalysts.



### Costs and Cost Effectiveness for SO x Reducing Cataly sts in Literature

Commercial data from Intercat for SOXGETTER ® have shown that 85% reduction in SOx, resulting in 50 ppmv emissions, can be achieved w ith 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 tota l 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 co st effectiveness will be approximately $6,000 per ton SOx removed. 14

FIGURE 3-2 Efficiency of SO x Reducing Additives

In other references shown in Table 3-6, a ra nge 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 Davi son 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) Shor t-term testing with SOx reducing additiv es at a refinery in the District.



## 3.3.2 Wet Gas Scrubbers

Wet scrubbing is used to control both SOx and part iculate. 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 cont rol 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 reag ents, 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 separa ted in a purge treatment system and th e treated water, free of suspended solids, are either discharged or recycled. On e 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 fl ue 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, Presen ted at PETROTECH 6 th International Petroleum Confer ence 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 liqui d/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 impac tion 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 stre am 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 modu le. The droplet separator module consists of a bank of parallel spin vanes. The heavy, super-s aturated, 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 co mponents of the wet scr ubber 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 efflue nt from the clarifier is oxidized with agitated air. Sulfites are converted to sulfates, and the chemical oxyge n demand (COD) is further reduced so that the effluent can be safely discharg ed 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 re generative 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 li quid 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 n on-regenerative wet gas scrubber. One example of a regenerative scrubber is the proprie tary 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, Presen ted at PETROTECH 6 th International Petroleum Confer ence 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 Scrubbi ng 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 LABS ORB scrubbing system is capable of reducing High Capacity Clarifier Solids to Dis p osal

Oxidation Units Effluent Dischar g e d Purge from

Scrubber

Air SPRAY MODULE

Filtering Module

R ec ir cu l at i o n P u m ps FILTERING MODULE

Absorber Vessel Recirculation Pumps Flue Gas Inle t DROPLET SEPARATOR MODULE Flue Gas Outle t

Caustic Reagent Inlet Pur g e Strea m Makeu p Water Inle tFinal 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 se ction which typically includes a stripper and a heat exchanger.

In the scrubbing side of the regenerative scrubb ing system, the quench pre-scrubber is used to wash out the large partic les carried over, as well as acid components in th e 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, pack ed with high-efficien t structural packing materials. In some scenarios, such as when th e inlet SO2 concentration is low, a multiple-staged packed bed scrubber, or a spray and plate tower scrubber, is re commended to achieve an outlet concentration of 25 ppmv or less.

In the regenerative side of the regenerative sc rubbing 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 conden sed-SO2 gas stream is sent back to the SRU

for further treatment.

FIGURE 3-5 LABSORB Regenerative Wet Scrubbi ng System Developed By BELCO

Quench

Scrubber Packed

Bed

Absorber Heat Exchangers

Clarifier Flue Gas from CO Boiler (>1000 ppmv SO2)

Wate r Flue Gas to Stack (<25 ppmv SO2)

Water to Treatment or Discharged Stripper

Stea m Condensed

SO2 to SRU

Buffer

Tank

Solids to Disposal

REGENERATION SIDE SCRUBBING SIDE CondensateFinal 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 mo re 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 reagen ts used in the regenerative system, and the byproducts (e.g. elemental sulfur) can be sold. The annual operati ng costs of a regenerative system are estimated to be about 35% of the annual ope rating costs of a non-regenerative system as shown in Table 3- 7. Table 3-8 presents an estimate for cost e ffectiveness of the wet gas scrubber reported in literature, ranging from $500 - $3,0 00 per ton to achieve 25 ppmv. As shown later, a 5 ppmv

and lower level has also been achieved. Th e consultants and staff’s estimated a cost effectiveness of $12,000 - $76,000 per ton to achiev e 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 Co mparing 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-da y 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 Ma nagement Association (MARAM A), January 31, 2007; 3) Motiva Enterprises LLC, Equilon Enterprises LLC, and Deer Park Refining Limite d Partnership Civil Judicial Settlement, March 21, 2001; 4) BP Texas City Site – Texas City, Texas – 2004 Environmental Statement , June 2005. 5) Valero installed tw o 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 indi cates 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 FC CUs with average capacity of less than 150,000 barrels feed per day, while wet gas scrubbers are typically th e 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 in formation for the FCCU’s wet gas scrubbers. Some air pollution control agencies do not require a faci lity 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 scru bbers. All ten FCCU’s wet gas scrubbers achieved a leve l below 18 ppmv. Six out of the ten FCCUs overly surpassed the performance of a typical we t gas scrubber (i.e., 25 ppmv SO2 at 0% O2, 365-day rolling average and 50 ppmvd at 0% O2, 7-day rolling av erage 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 ach ievable 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 th at wet gas scrubbers can achiev e 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 Quar terly, 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 SO 2 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 esti mated by SCAQMD staff based on the average refinery gas throughputs. CE MS/source test data shown in Appendix C of this report. 2) Telephone conversations and emails between Minh Pham (SCAQMD) and Ravi Rangan of De laware Department of Natural Resources an d Environmental Control (DNREC) between April 2008 and July 2009. Pe rmit for Delaware City Refinery (aka Premcor Refining) is no w 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 abso rber, and a caustic polisher to reduce both SOx and pa rticulate emissions for their FCCU and their flui dized 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 red uce 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 refine ry 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 (SCA QMD) and Mary Pettyjohn of Arkansas Department of Environmenta l 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 BA RCT level of 5 ppmv at 0% O2, 365-day average for all remaining five FCCUs based on th e 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 base d on ETS/AEC are shown in Table 3-11

TABLE 3-11
Emission Reductions & Cost Effe ctiveness 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 Fina l Report for Module 3A, April 20, 2009Final 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 refi neries in the U.S. successfully operating wet gas scrubbers to achieve a level below 5 ppmv, staff concurre d with the consultants’ recommendation, and proposed to set BARCT for FCCU s at 5 ppmv, 0% O2, 365-day av erage. However, because Refinery 2 has heavily treated th eir 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 scen ario from its proposal and subsequent analyses. With this refinement , the anticipated emission reductions and weighted average cost effectiveness from this process cate gory are estimated as shown below. Staff hired Norton Engineering Consultants (NEC) to revi ew the cost analyses conducted by ETS/AEC. The cost effectiveness estimated by using NEC recommendations is shown in Table 13- 1 2.

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 dolla rs, and staff revised the cost-effectiveness based on the revised data. 3) The weighted average cost-effectiveness numbers shown here were calc ulated excluding the costs and emission reductions associated with early reductions, and excluding the costs and emission reductions

associated with the cost-ine ffective case for Refinery 2.

The proposed BARCT is then equal to a pproximately 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 almo st all of the processes in refinery such as distillation, hydrotreatin g, fluid catalytic cracking, alkylati on, reforming, and delayed coking. Figure 4-1 provides a simplified diagram of the pr ocesses where boilers a nd heaters are used.

The refinery heaters and boilers primarily use refi nery gas, one of the products generated at the refinery. As a back-up fuel, most of these boile rs and heaters use natural gas. Liquid fuel or solid fuel is rarely used in refinery boilers an d heaters. The combustion of sulfur or sulfur compounds in fuel generates sulfur dioxide (SO 2 ), with a small amount being further oxidized to sulfur trioxide (SO 3 ):

S + O 2 = SO 2 SO 2 + 1⁄2 O 2 = SO 3

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 fr om 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

As p halts Jet

, Diesel Gasoline

Jet

, Diesel

Gasoline Refinery Gas

LPGFinal 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 a llocations based on the highest reported fuel usage from 1987 to 1992, and an emi ssion factor of 6.76 lbs SOx per million cubic foot of refinery fuel gas. This emission fact or 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 refineri es reported a total of 3 tons per day SOx emissions from all

300 boilers and heaters curren tly operated at the refineries. Tabl e 4-2 presents a list of the top 16 emitters in this category whic h 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 0.02Final 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 Surv ey, the refineries repor ted that the refinery fuel gas is generally hydrotreated with Amine so lution to reduce sulfur before being combusted in the refinery heaters and boilers . The sulfur contents in the re finery fuel gas were reported to be in a range of 49 ppmv – 327 ppmv. The SOx c oncentrations in in th e boilers/heaters’ stacks vary from 6.5 pp mv – 44 ppmv



## 4.3 Control Technology

Generally, SOx emissions from boilers a nd 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. sti ll use solid fuel or liquid fuel. Solid fuel and liquid fuel typically contain higher sulfur content than refinery fu el gas or natural gas, thus the combustion of solid fuel and liquid fuel generate s 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/liqui d fuel in all boilers an d heaters operated at the

refineries. 20, 21 According to these settlement agreemen ts, 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.

2:96CV095RLFinal 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 re finery 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 use d, must contain less than 15 pp mw (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 SO x 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, whic h 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 emissi ons from boilers/heaters that use refinery gas. Because the allocations and the 2005 emissions from the combustion solid/liquid fuel in refineries are negligible co mpared 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 re quired 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 va rious acid gas processing units such as an amine or Merox treating unit for removal of sour com ponents (e.g. hydrogen sulfid e, 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, a nd H2S is evolved as acid gas which is then fed to the SRUs/tail gas treatment as discussed in Chap ter 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 em issions 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 f eet 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 de tails 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 rebo iler heater, 138 mmbtu/hr
Boiler, 526 mmbtu/hr Inlet standard: 25 ppmv as H 2 S, 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 char ge heater, 21 mmbtu/hr
Catalytic reforming char ge 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 react or heater, 311 mmbtu/hr
Butane conversion isostripper reboiler, 222 mmbtu/hr
Delayed coking charge heaters, 99 mmbtu/hr Inlet standard: 35 ppmv, as H 2 S, 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 re ducing the sulfur content of fuel before it is combusted, flue gas scrubbing is aiming at reduci ng 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 Unio n (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 dr yer scrubbers and 2) dry injectio n scrubbers. In dry scrubbers, a dry calcium and sodium based alkaline powered sorbent is used to absorb SO 2 . A spray dryer scrubber refers to a configura tion where the reaction between SO 2 and the dry sorbent takes place in a dedicated reactor (or scrubber), whereas in th e 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 in jection ports may be required for even distribution of dry sorbent in the boilers/heaters or ductwork. Cyclones and ESPs are typically used downstrea m of a dry scrubber to remove the particulate formed in the process. Dry injection scrubbers can achieve about 50% - 80% remova l 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

SO 2 . 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 im pacted with aqueous lime or limestone slurry for

SO 2 absorption. Particulate formed in the spray tower falls to the bottom of the spray tower, where it is collected and recycled back to the sc rubber 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 scrubbe rs are used extensively to control SOx and

PM from FCCUs at several refineries in the U. S. A wet scrubber desi gned by BELCO includes a spray module with two additional modules, a filte ring 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 e xpected 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, inle t SOx, and amount of emissions reduced. 26 Using a wet gas scrubber may allow the re finery 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 distilla tion 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 studie d the technologies for pr e-treatment of fuel gas prior to combustion, as well as the technologies fo r 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 refi nery fuel gas be retained as BARCT. Regarding the post-treatment of flue gas from boilers/hea ters after combustion, th e consultants found that the wet gas scrubbers were not cost-effective. N onetheless, the consultants found that the fuel gas at some refineries can be further reduced to the Tier I BARCT whic h results in about 0.89 tons per day emission reductions from the 2005 base line. 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., Presen ted in the Petrotech 7 th International Oil & Gas Conference, January 24, 2007Final 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 refineri es include a sulfur rec overy unit (Claus unit) followed by a tail gas treatment unit (e.g. Amin e treating) to maximize the removal of H 2 S.

The Claus sulfur recovery unit, as shown in Fi gure 5-1, consists of a reactor, converters and condensers. The two reactions proceed in the Cl aus sulfur recovery unit are exothermic. The

first reaction occurs in the Clau s reactor, where a portion of H 2 S reacts with air to form SO 2

.

2H 2 S + 2O 2 → SO 2 + S + 2H 2 0

The second reaction takes place in the catalytic c onverter where SO 2 reacts with H 2 S to form liquid elemental sulfur.

2H 2 S + SO 2 → 3S + 2H 2 0

Side reactions also occur which produce car bonyl sulfide (COS) a nd carbon disulfide (CS 2 ), which have presented problems in many Claus plan t operations due to the fact that they cannot be easily converted to elementa l sulfur and carbon dioxide,

Liquid sulfur is recovered after the final condens er. 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 th e tail gas, the tail gas is sent to a tail gas treatment process, such as amine, dietha nol amine (DEA), SCOT , Wellman-Lord, and

FLEXSORB. First

Converter First

Condenser Second

Converter Second

Condenser Reacto r Tail Gas Acid Gas

Li q uid Sulfu rFinal 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 reduc ed in a catalytic reactor to H 2 S. The H 2 S is absorbed in the amine (or other absorbent) in the H 2 S absorber, steam-stripped from the absorbent solution in the

H 2 S stripper, concentrated, and recycled back to th e 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 capaci ty of the sulfur recovery unit. The residual

H 2 S in the treated gas from the absorber is typi cally vented to a thermal oxidizer where it is

oxidized to SO 2 before emitting to the atmosphere.

FIGURE 5-2
Tail Gas Treatment – SCOT Process

Figure 5-3 shows a simplified diagra m of Wellman-Lord tail gas treatment process. The sulfur compounds in the tail gas are first inci nerated with air to oxidize to SO 2 . After the incinerator, the tail gas enters a SO 2 absorber, where the SO 2 is absorbed in typically sodium sulfite (Na 2 SO 3 ) solution to form sodium bisulfite (NaHSO 3 ) and sodium pyrosulfate (Na 2 S 2 O 5 ). The

absorbent rich in SO 2 is then stripped, and the SO 2 is recycled back to the Claus gas. The residual sulfur compounds in th e treated tail gas from the SO 2 absorber is typically vented to a

thermal oxidizer where it is oxidized to SO 2 before emitting to the atmosphere. Catalytic

Reactor

SO 2 reduced to

H 2 S Acid Gas Recycled

Back to Claus

Unit

Absorbe r H 2 S
Stri pp e r

Claus Unit

Off-Gas Thermal

Oxidizer To Stac k

H 2 S

AbsorberFinal 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 issu ed emission allocations for thei r sulfur recovery - tail gas treatment unit based on the highest report ed 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 Rec overy -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

SO 2 Acid Gas Recycled
Back to Claus

Unit
SO 2 Stri pp e r

Claus Unit

Off-Gas Thermal

Oxidizer To Stac k

SO 2 AbsorberFinal 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 Rec overy -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 th ese 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 pr ovided that the total emissions from the facility are below facility emi ssion caps. The allocati ons provided to these un its since 1993 have not been adjusted even though there may have emergi ng technologies that can be used to further reduce SOx emissions from these units. Compari ng the allocations provid ed 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 ha ve been slightly impr oved 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 refineri es 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 a nd tail gas treatment. All six refineries have

thermal oxidizers at the end of th eir tail gas treatment units. A re finery 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 concentrati ons 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 pp mv for Refinery B, and 98 ppmv for Refinery FFinal 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 Reco very – 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 oxidize r to oxidize the remaining H 2 S. The Claus sulfur recovery, tail gas treatment and ther mal 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 SO 2 with the use of therma l oxidizers, or 10 ppmv

H 2 S without the use of thermal oxi dizers). The three main strate gies that can be employed to

further reduce SO 2 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 stag e of the Claus unit to promote the oxidation of

H 2 S to SO 2 without the use of a flame. SELECTO X catalyst has helped to increase the efficiency of sulfur recovery unit from 90% to 97%. SELECTOX has been used in San JoaquinFinal 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 effi ciency from a typical 96% - 97% to 99.8% - 99.9%. Testing on the tail gas unit at the Motiva Enterprise s’ Port Arthur refinery demonstrated that the

stack SO 2 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 c ontains three to four catalytic converters. The first two or three cata lytic converters use the Claus catalysts, while the

last reactor uses a selective oxidation cat alyst that highly selective and oxidize H 2 S 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 reac tor to form H 2 S 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 recycl ed to the absorber, while and H 2 S 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 re move additional sulfur. Activated titanium oxide

is used to remove COS and CS 2 . Any remaining H 2 S 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 qui nine solution to absorb H 2 S in the tail gas. The absorbed H 2 S is

then oxidized to form a mixture of elem ental 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. Befo re entering the absorber, COS and CS 2 in the tail gas can also be eliminated by the use of cobalt molybdate cataly st 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 hyd rotreating reactor to convert SO 2 in the tail gas to H 2 S, and then

contacts H 2 S with Stretford solution in a liquid-gas ab sorber. The Stretford solution contains a mixture of vanadium salt, anthraquinone disulf onic acid (ADA), sodium carbonate, and sodium hydroxide. The vanadium salt act s as a catalyst to convert H 2 S into elemental sulfur. The recovering efficiency of the St retford process is about 99%.



### 5.3.2.5 FLEXSORB ®

The FLEXSORB process were developed by th e 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 H 2 S, organic sulfur to elemental sulfur. The efficiency of FLEXSORB is about 99.9+%. This technology has b een 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 a nd two oxidation stages. In a re duction stage, a highly selective SO2 reduction catalyst developed by Lawrence Be rkeley National Labor atory is used to

accelerate the reduction of SO 2 to elemental sulfur. After this stage, the remaining H 2 S is oxidized to form elemental sulfur under the pres ence 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 capa ble of recovering 99.9+% with or with the use of a proprietary Mobile Be d Absorber (MBA) where H 2 S and SO 2 are absorbed into a circulating

solution and converted to elemen tal sulfur in the presence of a chelated-iron catalyst. The solution leaving the MBA is then oxidized. E xhaust gas from the MBA is vented to the atmosphere and contains less than 10 ppmv H 2 S.

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 Reco very – 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 Refiner ies 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, th e tail gas from the Claus sulfur recovery unit is sent to an amine treatment process, which absorbs H 2 S, produces a concentrated H 2 S stream, and recycles the concentrated H 2 S stream to the front end of the SRU. The residual H 2 S in the treated gas is typically vented to a th ermal oxidizer where H2S is oxidized to SO 2 before emitting to the atmosphere. This approach t ypically 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 SO 2 . The

SO 2 is then captured by alkaline agent (e.g. s odium hydroxide caustic solution) in a wet gas scrubber, and the residual SO 2 not captured in the scrubber is discharged to the atmosphere. With this approach, there is no concentrated H 2 S stream recycles to th e front end of the SRU, and the overall sulfur recovery/removal efficien cy is increased to 99.95%, above the efficiency

of the current Claus SRU-Tail Gas Tr eatment 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-Re generative 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 Casp er 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 (Na 2 CO 3 ), or calcium based agents such as lime (CaO) or limestone (CaCO 3 ), however Sinclair Oil refinery and Casper refinery have sele cted caustic (NaOH) because:

─ Caustic was available as a 50% solution which could be pumped directly to the scrubber without further dilution or mixing. Soda as h or calcium based agents are only readily available as a powder and they would require an installation of a reagen t preparation station.

─ The reaction between SO 2 and caustic (NaOH) are relatively fast compared to the reaction of

SO 2 with calcium based reagents. The products, sodium sulfite (NaHSO 3 ) or sodium bisulfite salts (Na 2 SO 3 ) accumulated in the waste water stream, are soluble and can be

further oxidized to reduce the COD in the wa ste stream to the level acceptable to the municipal wastewater treatment plant. In contrast, the products calcium sulfite (CaSO 3 ) or calcium sulfate (CaSO 4 , aka gypsum) of the reaction between SO 2 and calcium based agents

are insoluble salts which are not easily removed fr om the scrubber solution.

Using caustic solution as a scrubbi ng agent has helped the refineri es to save on capital costs and annual operating costs, and improve the removal efficiency and operability of the system.

Most DynaWave scrubbers contain tw o 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 scrubbi ng 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, an d 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 th e caustic reagent, is a proprietary piece of equipment supplied by Mons anto Enviro-Chem System (MECS) which is very critical to the scrubber application. A rela tively large volume of sc rubbing liquid is injected counter to the gas flow to create a froth zone. Th e 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 th is turbulent region, the gas abso rption 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 SO 2 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 st age scrubbing can be turned off

when it is not needed.

FIGURE 5-4 DynaWave Wet Gas Scrubber Used for Sulfu r Recovery Tail Gas Treatment Unit

After passing through the third scrubbing stage, th e air stream will pass th rough a set of chevrons which are used to maximize the liquid droplet re moval. 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 oxid ized to sulfates in th e reservoir. In additi on 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 star ted 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, cogenerati on 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 inst alled and operate d 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 le vels of the sulfur re covery units in the Di strict reported by the facilities through the 2008 Su rvey are listed in Table 5-4. The SOx concentrations at the stack of the thermal oxidizers vary wide ly 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 2 nd 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 Dyn aWave scrubber at its Tula refinery which has already started up in 2006. The most recent 6-m onths 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 Dyn aWave 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 Co rporation, 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 co nsultants, 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 fo r SRU/TG into two areas.

⎯ For uncombusted tail gas, the consultants re commended a BARCT level of NSPS Subpart J (Ja), namely 10 ppm H2S and 300 pp m reduced sulfur species (total of H2S, COS, and CS2)

⎯ For the combusted tail gas, the consultants re commended 5 ppmv SOx @ 0% O2 as BARCT. The consultants indicated a level of 10 ppmv wo uld allow a greater numbe r of refineries to meet the overall BARCT level by the gas treatm ent 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 th e consultants on the leve l 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 $44.5kFinal 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 spen t sulfuric acid is decom posed to sulfur dioxide (SO 2 ) in a furnace:

S + O 2 = SO 2 Spent H 2 SO 4 = H 2 O + 1⁄2 O 2 + SO 2

The sulfur dioxide is then catalytica lly oxidized to sulfur trioxide (SO 3 ) in a multi-staged catalytic reactor (or converter). A typical catalyst used in the reactor is vanadium:

2SO 2 + O 2 = 2SO 3

The sulfur trioxide reacts w ith water in a absorbing tower to produce a strong sulfuric acid

solution.

SO 3 + H 2 O = H 2 SO 4

In a double absorption process, the SO 3 gas formed from the primary converter is se nt to a first

absorber where the SO3 is removed to form H 2 SO 4 . The remaining unconverted SO 2 and SO 3 are directed to a second set of convert er and absorber to further produce H 2 SO 4

.

FIGURE 6-1 Sulfuric Acid Manufacturing Process

The conversion to H 2 SO 4 is always incomplete, and is affect ed by the number of stages in the catalytic converter, the type and amount of cata lyst used, temperature and pressure, and the concentrations of the reactants, SO 2 and O 2 . A 98% - 99% conversion to H 2 SO 4 is typical. The Furnace
150 mmbtu/hr Sulfur Spent H 2 SO 4 H 2 S Waste

Heat
Boiler

Wate r Stea m

Fuel Oil

Natural Gas SO 2

Absorbers with

Mist Eliminators Catalytic

Convertor

Strong Acid SO 3

Stack

215 ft H-6 ft DIA SO 2 Acid Mist

Products 98% - 99% H 2 SO 4 Scrubbers
with Mist

Eliminators ESP

ESPFinal 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 abso rbers can be vented to ESPs, sc rubbers, and mist eliminators to

remove SO 2 and acid mist prior to venting to the atmo sphere. 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 faci lities in the District that oper ate a sulfuric aci d manufacturing plants. In 1993, allocations we re provided to these processe s based on an emission factor ranging from 4 lbs/ton acid produced to 9.478 lb s/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 expres sed as SO2; and NSPS requires a sulfuric acid manufacturing plan t to meet an emission level of 4 lb SO 2 per ton of 100% acid produced, maximum 2 hour average. The allocations pr ovided 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 aci d units that were built between the late 1920’s and late 1950’s. In 1990, these thr ee 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 SO 2 , there is acid mist generated from the absorber of the sulfuric acid manufacturing process. Acid mist is generated when SO 3 combines with water at temperature below the dew point of SO 3 . Acid mist is a very stable co mpound 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 processe s 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 repor ted their 2006 and 2007 emissions through the SCAQMD Survey conducted in 2008, as shown in Table 6-2. The produc tion 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 us es 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 emissi on 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/LA ER 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 su lfuric acid manufacturi ng plants in the U.S. have upgraded their converters and absorbers, used cesium promoted vanadium catalysts, and added tail gas scrubbers to m eet 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 Justi ce 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 spen t 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 sulfur ic acid plants in Louisiana, Virginia, Ohio, and Kentucky. Under the recent settlements, the company has ag reed to install $66 mill ion 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 opti on to install the $87 m illion additional control technologies or ceasing operations. All four plants have to meet the lower standards ranging
from 1.7 lbs – 2.4 lbs SO 2 per ton acid produced by March 1, 2012. When fullyFinal 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 approximate ly $50 million to upgrade air pollution control at their eight production plants in four states across the country to reduce SO 2 emissions by approximately 95%. As shown in Table 6-4, th e consent decree requires the installation of wet gas scrubbers or double absorption technolo gy 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 SO 2 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 rolli ng 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 sulf uric acid manufacturing plants has been improved significantly. The curren t 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 contro l 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.htmlFinal 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 feas ibility and costs of control are summarized in Part 2 of the Staff Report, and the non-confiden tial portions of the analyses (NEXIDEA & NEC) are available for public information. After consider ing all feasible technologies, the consultants’ recommendation for BARCT level, which staff c oncurred with, is 10 ppmv for sulfuric acid plants. The consultants’ estimates are as follows:

TABLE 6-5
Emission Reductions and Cost Eff ectiveness 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. 8 3.3 k - $8.8k Average: $3.4k

Comparing to an average Tier I level of 3.93 lbs/ton, the pro posed new BARCT of 0.14 lbs/ton
reflects a 97% reduction fr om 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 reco rded 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 cont ainer glass manufacturing facility located in Vernon. The company manufactures glass bottles, glass wares, pr essed & blown glass, tempered glass, as well as safety glass. The manufacturin g process contains four ph ases 1) preparation of raw material, 2) melting in a furnace, 3) formi ng, and 4) finishing. Figure 7-1 is a simplified diagram for a typical gla ss manufacturing process.

Raw materials, which include sand, limestone, a nd soda ash, are crushed and mixed with cullets to ensure homogeneous melting. The raw mate rials are then conveyed to a continuous regenerative side-port melting furnace. As th e materials enter the melting furnace through a feeder, they float on the top of the molten glass al ready in the furnace, melt, and eventually flow to a refiner section, and then fore hearths, fo rming machine, and annealing ovens. The final products undergo inspection, testin g, 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 FurnacesSide-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) ESPsFinal 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 contribute s over 99% of the total emissions from a glass plant. There are currently two melting furnace s 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 perm it condition of 80% efficiency. The scrubbers are manufactured by PPC Industries, use sodium b i/sesquicarbonate as scrubbing agent, have two passes, and about 101 ft in length and 2ft 8 in diameter. The outle t flue gases from the scrubbers

are directed to a common manifold and are ve nted 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 th eir furnaces are presented in Table 7-1. These

allocations were estimated based on SOx em ission factors ranging from 2.12 lbs/ton to 3.15 lbs/ton of glass pulled and thei r peak activities in 1992. The to tal 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 dedicate d 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 th e first CEMS, 69 ppmv for the second CEMS, and 85 ppmv for the third CEMS. In addition to Owens-Brockway, Sa int-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 ha s 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 th at 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 pu lled, 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. a nd required Saint-Gobain to install st ate-of-the-art pollu tion 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 permitt ed 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 st arted 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 mu st 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 C ontainers 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 AP CD 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% contro l 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 Sa int-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 th ese furnaces is limited to 15 ppmv by weight of sulfur (0.0015%). 3) Based on the most recent sour ce 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 Tr i-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 fo r BARCT is a level of 1 ppmv or below:

TABLE 7-4
Emission Reductions and Cost E ffectiveness 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 Furn aces, 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 gla ss facility in the basin. Because of the economic reason, staff’s recommendation for BARCT is 5 ppmv or be low. 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/tonFinal 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 compa ny 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 Wi lmington, 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 stor age barn. The screened and drie d green coke is introduced into the high end of the rotary kiln, 3 feet diamet er x 270 ft long, is tumbled by rotation, moves down

the kiln countercurrent to a hot stream of co mbustion air produced by the combustion of natural gas or oil. The kiln temperat ures 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, th e 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 transpor ted by trucks to the Port of Long Beach for export, or is loaded into railcars for shipment s to domestic customers. A simplified process diagram of the calcining proce ss 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

Coole r Storage
Tanks Turbine-Generato r

ElectricityFinal Staff Report – Part 1 Chapter 8 – Coke Calcining

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 79 November 2, 2010 BP Wilmington produces approximately 400,000 s hort tons per year of calcined products. 43 The Wilmington coke calciner is limited to a maxi mum 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 th e aluminum industry, and fuel gr ade 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 alloca tions 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 complia nce with SCAQMD Ru le 1119 – Petroleum Coke Calcining Operations – Oxides of Sulf ur, adopted March 2, 1979, which requires that the uncontrolled SOx emissions from coke calcining ope rations 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 calci ner 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, 2002Final 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 c ontrol technology for the BP Wi lmington 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 syst em. Calcium hydroxide (CaOH) slurry is the absorbing medium for SO 2 control. Figure 8-2 shows a simp lified process diagram for the dry scrubber system at BP Wilmington..

FIGURE 8-2 Dry FGD System for Coke Ca lciner 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 verificati on of guarantees. Producti on 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 le vels 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 ra te of 1,848 tons green coke pe r day. The processing rate was substantially higher than the processing rate us ed for the original desi gn 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 Slurr y

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 th at the performance of the dry scrubber in 2005- 2007 exceeded the design levels. The control e fficiencies for the dr y 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 M easured 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 calcin ers at Cherry Point Refinery in Blaine, Washington. Originally, BP voluntary installed a we t 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 ac id 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, co rrected 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 part iculate 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 effi ciencies to achieve emission rates ranging from 0.21 lb – 1.64 lb SOx per ton calcined coke; and that a combin ation 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 fr om coke calciner is possible.

In September 2008, staff, WSPA and the refineri es awarded a contract to NEXIDEA Inc. to conduct a feasibility and costs analysis of contro l technologies for coke cal ciner. A summary of the consultant (NEXIDEA)’s analys is 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 CalcinerFinal 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 Effectiv eness 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 NECFinal 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 wh ite 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, st aff 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 acqui sition; 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 ma terials are delivered to CPCC by truck or rail car.

Preparing the raw mix includes crushing, milling, bl ending and storage. Primary, secondary and tertiary crushers are used to crus h the raw materials until they are about 3⁄4 inch or smaller in size. Raw materials are then conveyed to rock storage silos. Belt conve yors 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 pr ocess 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 ox ides 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 o F;

― Calcining of calcium carbonates (CaCO 3 ) to form calcium oxides (CaO) and carbon dioxide (CO 2 ). This process occurs in th e calcining zone of the rotary kiln at temperatures of about

1100 o F – 1800 o F; andFinal 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 o F – 2700 o F.

The pyroprocessing process at CPCC is called a “l ong dry process” consisti ng 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 directi on. 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 o F 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 di fferent 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 Manufacturin g 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

LimestoneFinal 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 la st step of the manufacturing process. Up to 5% of gypsum is added to the cl inker during this stage to contro l 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 provide d 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 Ga s 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 CP CC’s kilns and steam boiler are presented in Table 9-2. The 2005 facility emissi ons 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 fr om the kilns and steam boiler are controlled by baghouses. Limestone used in the kilns and boiler creates an alka line environment that promotes a direct internal absorption of SO 2 . 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 repor ted 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 ch ange. The boiler used coal and natural gas as

combustion fuel. The emission rate for this co al 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 co ncentrations 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 co al fired boilers are describe d abundantly in literature. 50 Almost

all SO2 emission control technol ogies for coal-fired boilers ar e post-combustion control. The exception to this universal rule is found in the fl uidized bed steam boiler (Device ID 851) used at CPCC. Fluidized bed boilers generally opera te 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 convert ed to CaO at about 1500 degree F, and CaO captures SO2 to form CaSO4, which is thermo dynamically stable at 1500 – 1600 degree F. A removal efficiency of about 90% SO2 can be achi eved 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 Unio n (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 abso rb SO2. Sulfate or sulf ite formed are either disposed, or further processed fo r commercial use. Scrubbers are commonly classified based on the process conditions (wet versus dry); the product uti lization (throwaway ve rsus saleable); and the reagent utilization (once-through versus regenerable). Scrubbers are widely used in commercial applications such FCCU s (Chapter 3), utility/industria l boilers/heaters (Chapter 4), sulfur recovery and tail gas treatment (Chapter 5), sulfuric acid manufacturing (Chapter 6), container glass manufacturing (Chapt er 7), and coke calcining (Chapt er 8). Please refer to these chapters for further descrip tions on this technology.



## 9.3.3 Costs and Cost Effectiven ess 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 reporte d 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-A tlantic Northeast Visibility Union (MANE-VU), March

2005Final 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 fr om 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 e fficiency for each technology and a brief description for each t echnology 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 Mi d-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 devi ce may also be needed to further reduce SO2

emissions.



## 9.4.2 Process Control

The following process control can be used to re duce SOx emissions from the calciner kilns:

─ It has been found that having su fficient oxygen to stabilize th e alkali and calcium sulfate compounds formed in the burning zone of the rotary kiln minimizes SOx formation. The downside of this technique is th at 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 Unio n (MANE-VU), March 2005.

52 Best Available Retrofit Te chnology (BARCT) for Se lected 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 avoidi ng flame impingement in the bur ning zone, avoiding flame impingement on the clinker, or improving distribution of kiln f eed to equalize temperatures

in the kiln can minimize SO2 formation.

─ It has been found that when alka li 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 substantia lly. The downside of this technique is that the amount of alkali added, or the amount of py retic sulfur removed, are often limited by the product specifications or mark et and economic factors.



## 9.4.3 Lime or Limeston e Spray Dryer Absorber

Lime and limestone contains calcium, in the fo rm of calcium carbonate (CaCO3), which reacts with SO2 and captures SO2 to form of calcium sulf ate (CaSO4). Water is typically sprayed into

the feed at the end of the kiln or introduced th rough dilution air at the air coolers. Two most common spray dryer absorbers are the RMC Pacifi c's Alkaline Slurry Injection System and the EnviroCare Microfine Lime System. The RMC P acific 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 E nviroCare uses water suspension of finely pulverized calcium hydroxide Ca (OH)2 as scrubbing agent. Li me 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 ap plicable to all types of cement kilns to remove SOx and particulate matter simultaneously. A wet scr ubber 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 containi ng 20% limestone and 80% water is produced in a mixing tank and sprayed countercurrent to the gas fl ow, cools the gases, reacts with SO2 to form calcium sulfite (CaSO3), calcium sulfate (CaSO4), and gypsum whic h in turn precipitate at the bottom of the absorbing tower and must be dispos ed 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 contro l SOx from the cement kilns,

the costs and cost effectiveness of these technol ogies 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 Cont rol 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 Sel ected Non-Electric Genera ting 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 c ontrol technologies for cemen t kilns and coal-fired boiler. A summary of ETS, Inc.’s analysis is in Part 2 of the draft Sta ff Report. NEC indicated that they would recommend WGS as BARCT for both cement kilns a nd coal fired boilers but did not provided costs information. Th ey indicated that WGS would be more cost-effective than the technologies that ETS recommended. However, if the technologies r ecommended 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 SO

x /ton clinker 0.25 tpd SO

x $18.9 K per ton

Coal-Fired

Boiler 95% control ( ≤ 5 ppmv) --- 0.36 tpd SO

x $ 3.8 K per ton

Staff concurred with the consulta nts’ recommendation for the coal-fired boiler, which is not in operation, at this time, and suggested the follo wing 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 SO

x /ton

clinker 0.25 tpd SO

x $19.3 k per ton per ETS $26.8 k per ton based on input

from NECFinal 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 fr om the seven affected cat egories of sources. The CEMS supplier and the SOx detect ion range, both low and high ra nges, are presented in Table

10-1.

TABLE 10-1 Current CEMS System

Sources Facility CEMS Supplier SO 2 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 me asuring 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 SO 2 (<10 ppm level), there are currently two main extractive methods for sampling the flue gas fr om a stack: dilution-ex tractive and extractive

non-dilution.



## 10.1 Dilution-Extractive

This sample acquisition method allows for the samp ling and detection of fl ue 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 (typical ly in a 100:1 ratio) before analysis. The

53 The author for Chapte r 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 SO 2 analyzer, since the diluted pollutant concentration is

near an ambient concentration level.



## 10.2 Extractive Non-Dilution

This sample acquisition method requires that th e sample be clean and dry for measurement. Therefore, significant emphasis must be placed on pa rticulate 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 syst em. Usually, the technology employed involves refrigerated condensers, thermoelectric chille rs, or gas permeation dryers. The cleaned, dry sample is then analyzed via an SO 2 gas analyzer.

For both sample acquisition methods, gas clea nup 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 SO 2 is soluble in water.

The majority of the CEMS analyzers curren tly installed at SOx RECLAIM major sources employ extractive non-dilution sampling, and has the capability of monitoring in the 25ppm SO 2 full span range (FSR). As expected, some upgra des may have to be performed to the existing systems to achieve readability in the lower ppm SO 2 full span ranges. The first choice will be

whether to install a dilution-extr active system with an ambient SO 2 analyzer as a replacement for an extractive non-dilution system. Both dilution-extr active and extractive non-dilution systems

can be installed in SO

x RECLAIM source category equipment. However, some process-specific stack conditions may determine which type of sy stem will work best at sample cleanup and analyte detection.

If sample dilution is determined as the best method for SO 2 detection, a completely new sampling system must be installed to measure pollu tant 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 hard ware, an ambient analyzer, plus integration hardware (cabinet, calibration hardware, programmable logic c ontroller, and data acquisition system). The estimated cost for a new dilu tion-extractive system, in cluding installation, is around $250,000. Since SO 2 will be detected on a wet basis, other criteria pollutants such as

NO

x and CO may also be detected on a wet basis. New analyzers w ill have to be installed for these respective analytes in order to be sampled from the same dilution probe.

If a facility is currently operati ng an extractive non-dilution system and opts to continue criteria pollutant measurements on a dry basis, the tw o essential components required for an upgrade

would be a new SO 2 gas analyzer and a gas conditioning system, such as a Nafion-based permeation drying system. Ametek Process In struments, for example, manufactures an SO 2 gas analyzer whose minimum full scale is from 0-25 ppm SO 2 . 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 SO 2 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 cer tain critical hardware component s (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 estim ated cost for a new extractive non-dilution system, including inst allation, is also around $250,000.

However, if a facility that ope rates an extractive non-dilution sy stem wants to only replace the

SO 2 analyzer and install a stack–m ounted, Nafion-based, permeati on drying system, the cost is much less: around $35,000. The operator can conti nue 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 us es industry-proven technology that achieves the re quired calibration results, analyte measurements, and valid Relativ e Accuracy Testing Audit (RATA) results.

Due to each individual facility ’s equipment setup, the CEMS sh elter may or may not require

relocation. The retrofits menti oned above are applicable to a scenario wher e the shelter is not being relocated. In this scenario, the sampli ng 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 ma y reuse and move the existing shel ter 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 ca n accommodate an an alyzer 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 serv ices 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 SO 2 analyzer replacement at CEMS rack $20,000Final 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 se nt to the facilities in July 2009 to gather information on the water usage at the facilities . The facility’s res ponses to this Survey Questionnaire were summarized in Table 11-1. St aff’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 wate r) 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 ga llons 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 leve l 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 th ey can support the modest 2% increase in water demand of this project. The wa ter suppliers indicated to sta ff that they can provide the

amount of water increase.

54 I nformation on water demand listed in the consultants’ final report for SRU/TGTU’s wet gas scrubbers were incorrect. Staff used information prov ided directly by the wet gas scrubber s’ 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 sc rubbers 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% in crease 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 supplie r (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 faci lities reported that they have no cap in the amount of water (fresh or recy cled) that they can purchase from the water suppliers. Some of the refineri es 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 ca p 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 Tabl e 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 us ed in these major refineries is recycled water. The suppliers of recycled wa ter indicated that they are working in expanding their capacity to supply recycled water to the faciliti es in the basin and can supply the water demand increase for this project.

⎯ Pumping capacity remained fo r in-house ground water wells. As shown in Table 11-1, seven of the eleven affected facilities have ground wa ter wells. All seven facilities have unused pumping capacity. The remain ing 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 calci ner 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 s uppliers 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 Tabl e 10-2 and staff’s collected information, staff believes the wastewater impacts from this project would be less than signi ficant because of the following reasons:

⎯ Small increase in discharge . As shown in Table 11-2, the pr oject would gene rate about 2% increase in wastewater (ra nge from <1% - 11%).

⎯ Wastewater treatment & disc harge capacity available. As shown in Table 11-2, the facilities have available discharge capacities. Their on-s ite wastewater treatment plan can handle the small increase. In addition, since the increase in discharge is less th an 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 c onsent 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 1Chapter 11 – Water & Wastewater_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 99 November 2, 2010TABLE 11-1 – Water Demand InformationRef B Ref A Ref D Ref C Ref E Ref FFCCU MM gals/yr 28 26 18 16SRUs (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 650MM gals/yr 83 55 83 6 23 16MM gals/day 0.23 0.15 0.23 0.02 0.06 0.04MM gals/yr 4,468 3,792 3,150 3,154 2,102 639MM gals/day 12 10 9 9 6 2Fresh water 0.05 (<1%) 1,008 (26%) 0 12% not provided not providedCooling tower 1,682 (41%) 1,440 (38%) 1,100 (35%) not provided 50% not providedBoiler feed 0.7 (16%) 1,344 (36%) 860 (27%) not provided 25% not providedOthers 2,785 (41%) 0 1.190 (38%) not provided 25% not provided% Increase = (Increase in Usage /Current Usage)2% 1% 3% 0% 1% 3%Groundwater Wells 3 No well 62 active wells (1 at eachsite)3 wells total atrefinery 1 well atsulfur plantNo wellMax Allocation for Pumping MM gals/yr5,309 acre-ft/yr = 1,730MM gals/yr = 3,291gpm2,570 acre-ft/yr = 837MM gals/yr = 1,593gpm2,500 gpm3,432 acre-ft/yr =1,118 MM gals/yr =2,128 gpmCurrent Rate of Pumping MM gals/yr1,727 acre-ft = 563 MMgals/yr = 1,071 gpm526 MM gals/yr =1,000 gpmBetween 600 gpm - 1,800gpm5,000 acre-ft/yr withlease agreementsUnused Pumping Capacity?Yes(67% remained)Yes(37% remained)YesYes with leaseagreementsRecycled Water Usage MM gals/yr 2,234 - 4,021 2,820 2,048 No No 0% Usage of Recycled Water 50% - 90% 74% 65% 0% 0% 0%Water Supplier CWS/WBMWD WBMWDWBMWD (65%),MWD (24%) andgroundwater (11%)CWS & LADWP LADWPLADWP (fresh water)& Air Products (smallquality RO)Maximum Purchase Limit? No limit No limit No limit No limit No limit No limitCONCLUSIONNo limit from watersupplier. Groundwater is available.Nomimal increase of2% can be met.(note 1)No limit from watersupplier. Nomimalincrease of 2% canbe met. (note 2)No limit from watersupplier. Groundwater is available.Nomimal increase of2% can be met.No limit from watersupplier. Ground-wateris available. Nomimalincrease of 2% can bemet.No limit from watersupplier. Groundwater is availablewith leaseagreement. Nomimalincrease of 2% canbe met.No limit from watersupplier. Nomimalincrease of 2% canbe met. (note 7)Increase in Water Usage due toRECLAIMCurrent Water Usage (Fresh andRecycled)MM gals/yrFinal Staff Report – Part 1Chapter 11 – Water & Wastewater_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 100 November 2, 2010TABLE 11-1 – Water Demand Information (Cont.)BP Coke Rhodia OwensB (2 WGSs) CPCC TotalFCCU MM gals/yr88SRUs (Revised Numbers) MM gals/yr155Coke Calciner MM gals/yr 1515Sulfuric Acid Plant MM gals/yr 77Glass MM gals/yr 20 20Cement MM gals/yr40 40Boilers/Heaters (fuel gas) MM gals/yr23MM gals/yr 15 7 20 40 350MM gals/day 0.04 0.02 0.06 0.11 0.96MM gals/yr 394 266 46 1,200 19,211MM gals/day 1 1 0 3 53Fresh waternot providedCooling tower 197 (50%) 226 (85%) not provided 5%Boiler feednot providedOthers 197 (50%) 40 (15%) not provided 95%% Increase = (Increase in Usage /Current Usage)4% 3% 44% 3% 1.8%Groundwater Wells No well 1 No well 5Max Allocation for Pumping MM gals/yr521 acre-ft= 170 MM gals/yrNo limitCurrent Rate of Pumping MM gals/yr165 acre-ft= 54 MM gals/yr1.9 MM gals/dayUnused Pumping Capacity?Yes.(68% remained)No limitRecycled 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 VernonRiverside Highland Waterfor potable an ind waterfrom wells.Maximum Purchase Limit? No limit No limit Not reported No limitCONCLUSIONNo limit from watersupplier. Nomimalincrease of 2% can bemet. (note 8)Ground water isavailable and no capfrom water supplier.Nomimal increase of2% can be met.(note 9)Wet gas scrubbers are pastpractice. Percent increasein water is meaningful butcan be met.No limit on groundwaterpumping. Nomimalincrease of 2% can be met.This project is expected toresult in less than 2%increse in water demand.Adequate supply of wateris available.Increase in Water Usage due toRECLAIMCurrent Water Usage (Fresh andRecycled)MM gals/yrFinal Staff Report – Part 1Chapter 11 – Water & Wastewater_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 101 November 2, 2010TABLE 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 recycled water supply but thefacility may have to pay a 21% increase in price of water in2009, and may have been required to reduce water usage by 20%2. Information from survey responses submitted by this facilityon August 6, 2009. The facility indicated that there was no cap on water supply, however the WBMWDmay mandate a 20% reduction in near future.3. - 6. Reserved7. 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, however LADWP must reviewany increase to assure that there is nophysical 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 do expectto pay higher feeson discharged wastewater because the fees on dischargedwastewater are based on total dissolved solids and COD9. Rhodia water information from survey responses submitted by Rhodia on August 4, 2009.CIWMB = California Integrated Waste Management BoardCWS = California Water ServiceCRWQCB = California Regional Water Quality Control BoardDTSC = Department of Toxics Substance ControlLACBS = Los Angeles City Bureau of SanitationLACSD = Los Angeles County Sanitation DistrictLACDPW = Los Angeles County Department of Public WorksLADWP= Los Angeles Department Water & PowerMWD = Metropolitan Water DistrictNPDES = National Pollutant Discharge Elimination SystemWBMWD= West Basin Municipal Water DistrictFinal Staff Report – Part 1Chapter 11 – Water & Wastewater_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 102 November 2, 2010TABLE 11-2 – Wastewater InformationRef B Ref A Ref D Ref C Ref E Ref FFCCU MM gals/yr 13 12208 8SRUs (Revised Numbers) MM gals/yr 10 5 16Coke Calciner MM gals/yrSulfuric Acid Plant MM gals/yrGlass MM gals/yrCement MM gals/yrBoilers/Heaters (Fuel Gas) MM gals/yr 3.18 2.16 5.27 6.0940MM gals/yr 27 19 21 6 12 8MM gals/d 0.07 0.05 0.06 0.02 0.03 0.02gpm 51 36 40 12 23 15Wastewater TreatmentSystem?YesYes. Twosystems. (note 2)Yes Yes YesYes - not currentlyactive (note 6)Wastewater TreatmentCapacityCapacity is limited to8,000 gpm, normal4,000 gpm.1) Cap 5,000 gpm,avg 3,000 gpm. 2)Cap 2,000 gpm,avg 1,800 gpmCap is 3,500 gpmNormal rate is3,000 gpmThere is a permit limitat one site which hasa normal rate of 2,000gpm. There is no limitCap is 6,000 gpmNormal rate is2,215 gpm in dry &2,260 gpm in wet1.14 (note 6)Regulator LACSD CRWQCB LACSD LACSD LACSD LACSDDischarge Point LACSD Santa Monica Bay LACSD LACSD & LACBS LACSD LACSD & LACBSDischarge LimitHydraulically limitedto 8,000 gpm & limitin wet weather is5,200 gpmNo limitLimit in dryweather is 12,200gpm & in wetweather is 7,500gpmMax limit is 5,000 gpmat one site, and thereis no limit at therefineryMax limit is 14.4MM gals/day(10,000 gpm).(Note 5)Limit by LACSD to1.1 MM gals/day &limit in wet weatheris 1000 gpmCurrent Discharge 4,000 gpm7 MM gals/day.8.8 MM gals/dayin dry weather, 27MM gals/day inwet weather3,000 gpm2,000 gpm at one siteand 1,400 gpm at therefinery.2,215 gpm in dryweather and 2,260gpm in wet weather1.3 MM gals/day in2008 (note 6)Remaining Capacity =Discharge Limit - (CurrentDischarge + Increase)3,649 gpmhydraulically & 1149gpm in wet weatherNo limitIn dry weather =9,160 gpm & in wetweather = 4,460gpmNo limit at therefinery. At the othersite about 3,000 gpm7,717 gpmAlready discharged18% over the limit(note 6)% Increase=(Increase /Discharge Limit)<1% --- <1% 0.2% 0.2% 1.8%CONCLUSIONWastewatertreatment &discharge capacityare available. Noneed to reviseLACSD permit.(note 1)Wastewatertreatment anddischargecapacity areavailable.(note 2)Wastewatertreatment anddischargecapacity available.Discharge capacityavailable. Lessthan significantimpact.Less thansignificant impactNo need to reviseLACSDapplication Lessthan significantimpact. (note 6)Increase in DischargeFinal Staff Report – Part 1Chapter 11 – Water & Wastewater_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 103 November 2, 2010TABLE 11-2 – Wastewater Information (Cont.)BP Coke Rhodia OwensB CPCC TotalFCCU MM gals/yr61SRUs (Revised Numbers) MM gals/yr31Coke Calciner MM gals/yr 66Sulfuric Acid Plant MM gals/yr 44Glass MM gals/yr 5 5Cement MM gals/yr52 52Boilers/Heaters (Fuel Gas) MM gals/yrMM gals/yr 6 4 5 52 159MM gals/d 0.02 0.01 0.01 0.14 0.44gpm 11 8 10 99 302Wastewater TreatmentSystem?Yes. A basin for pHadjustment.Yes. On-site tanks forneutralization.Yes.No wastewater treatment.Percolation ponds on site.Wastewater TreatmentCapacity0.18 MM gals/day(based on 125 gpmpeak flow)0.6 MM gals/day(425 gpm)0.4 MM gals/day(250 gpm)Regulator LACSD LACSD & LACDPWLACSD & City ofVernonCalifornia Regional WaterControl Board, Santa AnaDischarge Point LACSD LACSD LACSD On siteDischarge Limit0.18 MM gals/day(based on 125 gpmpeak flow)0.6 MM gals/day (425 gpm)as shown on LACSD permit131.4 MM gals/yr(0.36 MM gals/day)(250 gpm)No limitCurrent Discharge0.09 MM gals/day(93,775 gpd or 65 gpmdaily average)Peak is 0.56 Mmgals /day(387 gpm), and average is 0.25MM gals/day (175 gpm)41.89 MM gals/yr(0.12 MM gals/day)0.45 MM gals/day dust slurryto evaporation ponds & 1.05MM gals/day of cooling waterwastes to percolation ponds.Remaining Capacity =Discharge Limit - (CurrentDischarge + 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 limitCONCLUSIONDischarge capacityavailable. Less thansignificant impact.(note 8)Discharge capacityavailable. Peak flow mustbe carefully managed.(note 9)Less than significantimpactsLess than significantimpactsLess than significantimpactsIncrease in DischargeFinal Staff Report – Part 1Chapter 11 – Water & Wastewater_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 104 November 2, 2010TABLE 11-2 – Wastewater Information (Cont.)Notes1. This facility reported a maximum treated capacity of 8,000 gpm(12 million gals per day) and a normal treated rate of 4,000gpm (6 million gals per day). SCAQMD data (e-mail fromHanh Le to Minh Pham on August 5, 2009) provided a slightly smaller discharge levels2. This facility has two distinct wastewater treatment systems. The first system has primary treatment only. The second system has both primary and secondary treatment. The facility alsohas wastewater storage capacity to handle surges due to storms and upset3. Reserved4. 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 thatthey did not expect to seeany significant impacts to their waste water treatment system5. For this facility, see e-mail from Sawsan Andawis to MinhPham on August 6, 2009. The facility reported that if they are over 25% baseload of waswater discharge limit, they will besubject to a large connection fee minimum of$7.8 MM & claimed that witha wet gas scrubber installation, they will exceed the25% baseload, which is unlikely to occur.6. From the Survey Responses submitted on August 8, 2009, the facility responded that they do not have a wastewater treatmentfacility, and currently send all wastewater to LACSD fortreatment. Currently, the permit given by LACSD has a cap7. Reserved8. Based on the Survey Responses submitted on August 10, 2009,the facility indicated that "Additional scope and cost should have been included to reduce/offset/treat the quantity generatedfrom this project....".9. For Rhodia, based on the Survey Responses submitted on August 4, 2009, all wastewater is pumped into above ground agitatedtanks and sodium hydoxide isadded to elevate the pHabove 6.0. The discharge limit is 0.6MM gals per day max (425 gals/min).CIWMB = California Integrated Waste Management BoardCWS = California Water ServiceCRWQCB = California Regional Water Quality Control BoardDTSC = Department of Toxics Substance ControlLACBS = Los Angeles City Bureau of SanitationLACSD = Los Angeles County Sanitation DistrictLACDPW = Los Angeles County Department of Public WorksLADWP= Los Angeles Department Water & PowerMWD = Metropolitan Water DistrictNPDES = National Pollutant Discharge Elimination SystemWBMWD= West Basin Municipal Water DistrictFinal 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 provid es a framework for water manage rs, legislators, and the public to consider options and make decisions regardin g 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 agricultu ral, urban, and environmental water uses to quantify the gap between water supplies and uses. The Plan also identifies and evaluates existing and proposed statewide dema nd management and wate r supply projects to

address the State’s water needs. The Californi a 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 wate r 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 Californ ia and challenges, presen ts the strategic plans for the state as well as for the 10 hydrologic regi ons, and identifies recommendations that will be incorporated statewide in the ne xt couple years; Volume 2 desc ribes 27 resource management strategies (e.g. reduce water demand, improve ope rational efficiency and transfers, increase water supply, improve water quality, practic e resources stewardship, and improve flood management) that can be implemented in a mi x and match fashion to help the 10 hydrologic regions to diversify their water portfolio and b ecome more regionally self-sufficient; Volume 3 contains specific regional reports, and each regi onal report includes a wa ter balance summary of water use and water supply for the region fr om 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 Strategi c 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 impl ements and coordinates program to improve water quality. In the “Expansive Growth” scenar io, 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 we bsite - http://www.waterplan.water.ca.gov/Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 106 November 2, 2010 A big picture of the current water demand and us e, 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 Hydr ologic Region. The South Coast region is the

California’s most urbanized and populous region with the larges t 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 Sa n Diego counties. The region has numerous sources of water supplies: imported water, su rface water, groundwater, recycled water, and desalination. According to Metropolitan Water Dist rict of Southern California (MWD), half of the water supplied to the Southe rn California is from local supplies (e.g. groundwater wells. lakes) and the other half is im ported water from Northern Califor nia via the State Water Projects (SWP) passing through the Sacramento-San Joa quin 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 contract ors take delivery and c onvey 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 Co ast region is the Colorado River. The DWR is entitled to 4.4 MAF per year from the Co lorado 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 th rough a 242-mile Colorado River Aqueduct to supply to the retailers in Southern California.

Another source of imported wa ter 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. Ho wever, this amount varies from year to year due to fluctuating precipitation in the Sierra Nevada Mountains

Local surface water (e.g. Lake Casitas, Lake Pir u, Castaic Lake, Lake Perris) plays an important part in the big picture of wate r supply to Southern California. More than 75 im pound structures are used to capture r unoff for direct use and groundwater r echarge, 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 insuffi cient 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 agenci es must rely on artificial rechar ge (e.g. using recycled water). The Water Replenishment District of Southern California (WRD) has the mission to manage and protect the groundwater supply in th e basin. In the past couple y ears, most basin adjudications

61 2009 California Water Plan Update, South Coast, Volume 3 Regional Report.Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 107 November 2, 2010 have resulted in either a reduction or no incr ease in the amount of groundwater that can be

extracted.

Within MWD’s service area, there are approxima tely 355,000 acre-feet of planned and permitted uses of recycled water supplie s. Actual use is approximate ly 209,000 acre-feet, mainly in golf course, landscape, irrigation, indu strial uses, construction applica tions, 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 wate r by LADWP is projected to approximately 50,000 acre-f eet 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 implem ent 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 MA F averaged from 1998-200 5 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 in crease in water demand of 0.145 MAF.

To meet the California’s water challenges, Governor Schwarzene gger 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 (S enate Bills No. 1, 6, 7, 8) and $11.14 billion bond. Senate Bill No. 1 establishes the framework to provi de a more reliable water supply to California and restore the Delta ecosystem. Senate Bill N o. 6 requires, for the first time in California’s history, that local agencies monitor the groundw ater 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 be ing diverted from the Delta and appropriates existing bond funds to various activities to benef it the Delta ecosystem a nd secure the reliability of the state’s water supply. In addition, th e newly funded bond of $11.14 billion is approved by the Governor to fund drought relief, water supply reliability, Delta sustaina bility, statewide water system operational improvements, conserva tion and watershed protection, groundwater protection, and water recycling and water conserva tion programs. A summar y of the four Senate Bills and bonds are provided in th e 2009 California Water Plan Update. 62 The focus of the next

section is to discuss the 20x2020 Water Conservati on 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 Comprehe nsive 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 Co nservation Plan

In February 2008, the Governor directed state agencies to develop a 20x2020 Water

Conservation Plan that aims to reduce statewid e 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 Depa rtment of Water Resour ces (DWR), State Water Resources Control Board (SWRCB), California Energy Commission (CEC ), Department of Public Health (DPH), California Public Util ities Commission (CPUC), Air Resources Board (ARB), California Bay-Delta Authority (CBDA), and the US Bureau of Reclamation (USBR),

with the contribution of the California Ur ban 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 a nd 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 whil e estimating baseline per capita urban water use to give credit to agencies that have promot ed recycled water in the past. Additional use of recycled water will be a signi ficant 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 supp lied by customers for their own use. The plan focuses on potable water supplied in municipa l distribution systems and does not include quantities of self-supplied water (groundwat er 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 urba n water use will never go down, therefore the plan aims at improving wate r supply reliability and water use efficiency.

5. This plan does not set target s for individual water suppliers. There are wide variations among water suppliers. This plan does not pr ovide specific guidance to move from regional planning targets to supplier-specific targets. Wa ter suppliers are to develop their own plan to meet the state goals.

The 20x2020 plan is based on the 2005 baseline urba n 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 usi ng the projected 2020 populat ion 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 approximat ely 8% of the total water us e in the South Coast region.Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 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, th e Agency Team held numerous public meetings/workshops to establish the conserva tion targets and develop recommendations for future actions to achieve the targets.

Many urban water suppliers currently implement a nd 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 a nd new measures are listed in Table 11-5.

The nine (9) Agency Team’s recommended actions to achieve the Governo r’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 enforcemen t of landscape design and irrigation programs and the development of new landscape programs

⎯ Mandate the landscape irrigation Be st Management Practices (BMP)Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 110 November 2, 2010 TABLE 11-4 List of Best Manage ment 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 restricti ons (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 ne w connections and re trofit of existing

unmetered connections

BMP5 Large landscape conservation programs and incentives

BMP6 High efficiency clothes-washing ma chine 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 toil et (ULFT) replacement programsFinal Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 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 incorpor ate improved methodologies and accelerate coverage goals

4. Reinforce efficiency codes and related BMPs

⎯ Obtain authorization for state standard s for high efficiency clothes washers

⎯ Support landscape irrigation equipment standards

⎯ Accelerate replacement of inefficient showerheads, toilets and urinals

⎯ Accelerate adoption of proven water sa ving 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 pub lic information and outreach campaign

7. Provide new or exercise existing enfor cement 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 enforcemen t tools for water suppliers

8. Investigate potential flexible implementation measures

⎯ Investigate requiring conservation offs ets 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 th e measure that would generate the most water savings. The two most important conservation m easures 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 comme rcial, institutional, and industrial sector. Interestingly though is that the conservation from water loss contro ls is as significant as the

conservation estimated for a dditional water recycling.Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 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 to tal water and potable water demand to the water demand and savings of the statewide strategi c plan of the South Coast Hydrologic Region. The total water demand for the proposed SOx RECLAIM project is a bout 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 Hydr ologic Region in 2020. Staff beli eves 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, Institutiona l 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 avai lable = 99,360 gals/day = 111 acre-ft per year. Percentage = 111 / 201,423 = 

### 0.05%

⎯ Potable water demand for scenario where wet ga s scrubbers are used if future supplies of recycled water are not available = 201,587 gals/day = 226 acre -ft per year. Pe rcentage = 226 /
201,423 = 

### 0.11%

⎯ Potable water demand for scenario where De SOx 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 (A ct) became effective on January 1, 1984, and requires that every urban water supplier that pr ovides municipal and industrial water to more than 3,000 customers, or supplies more than 3,000 acre-f eet per year (AFY) pr epare 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 thei r service area, focus primarily on water supply reliab ility and water use e fficiency 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 verifica tion 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 resour ces 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 wate r resources in California? Wh at are their effectiveness and how much water that they can help to conserve? To what extend does is recycled water use d

in the basin?

• How does the water demand increase for this SOx RECLAIM projec t measure up to the
overall water use in the basi n? Can the urban water supp liers supply this amount of increase? Can this amount of increase be mitigated?

The information on the water supply/demand and wate r reliability analysis in the UWMPs of the three major water suppliers in the basin, Los A ngeles Department of Water & Power (LADWP), West Basin Municipal Water Dist rict (WBMWD), and Metropolitan Water District of Southern California (MWD) are presented below.



### West Basin Municipal Water District (WBMWD)

The WBMWD is the sixth largest wa ter district in the state of Ca lifornia, servi ng 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 refine ries 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

_____________________________________________________________________________________________ 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 fe deral 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 Facilit y. The WBMWD is in the pro cess of expanding the capacity of its facility to double the amount of recycl ed water produced in 2013. To promote the use of recycled water, the WBMW D advances funds for retrof it expenses which can be reimbursed through the water bill s. The onsite plumbing retrof it costs are amortized over a 10 years period at WBMWD’s cost of funds. Re payment can be made using the differential between potable and recycled wate r rates so that customers never pay more than potable rate. Once the loan is repaid, the rate revert s back to the current recycled rate

⎯ The WBMWD incorporates all 14 Best Manage ment Practices (BMPs) recommended by the California Urban Water Conservation Council (C UWCC) such as distributing water-saving showerheads and toilets, sm art controllers, and conducti ng water recycling and water education workshops to increas e public awareness about wate r conservation and help to increase water reliability within the region. As an example, providing $50 rebates for customers to replace/install Ultr a-Low-Flush Toilet (ULFT) ha s 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 pr oactively 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 Res ources in 2011. As shown in its 2005 UWMP, the WBWMD is able to supply reliable water to m eet 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 UW MP 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, 2002-0 3, 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 Manage ment Plan, Chapter 4. 2) Supply re liability covers onl y water demand in municipal/industrial sectors and do es 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 28,065Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 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 Califo rnia Title 22 regulation) to ultra pure Reverse Osmosis water for groundwater inje ction and industrial boiler feed as shown in Table 11-9.

The recycled water from WBMWD is used in va rious commercial, instit utional 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 Wate r 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, an d ultra pure RO water. The consultants (ETS/AEC) have conservatively used a rate varying from $800 per acre-ft - $1,350 per a cre-ft to estimate the annual water costs for SOx RECLAIM project accordingly to the in formation given to them by the refineries.

The recycled water consumption by the three re fineries located in the WBMWD’s service areas is summarized in Table 11-10, side -by-side with the amount of recy cled water that the refineries reported to staff, and the potential increase de mand for this SOx RECLAIM project. The totalFinal Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 116 November 2, 2010 recycled water purchased by the three refine ries from WBMWD is a bout 18,945 acre-ft in 2008- 09. The total recycled water us age 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 A nnual Report, the WBWM D 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 approximate ly 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 implemen t 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 groundw ater 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 wa ter from Hyperion that has been treated

with microfiltration and treated twice with reverse osmosis. This water is used for high pr essure 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 Manage ment Plan, Chapter 8 – Water Recycling. 2) Rates from Chapter 7 of the WBMWD 2005 UWMP. 3) ETS/AEC has used a wa ter 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 11-10Final Staff Report – Part 1 Chapter 11 – Water & Wastewater

_____________________________________________________________________________________________ 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. Ca pability: 70,000 - 100,000
Note: 1) Refineries purchase a combinati on of nitrification, pure single pass RO, a nd ultra pure double pass RO. 2) Refinery’s recycled water use is about 90% - 95% of the total recycled wate r 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 distribu tion in the LADWP serv ice area is shown in Figure 11-3. It

should be noted that LADWP act ively 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 wa ter conservation effort s (e.g. ultra-low-flush toilet retrofit program, indoor and outdoor conser vation), 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 con tingency plan with actions that can be undertaken in response to water supply shortages, incl uding up to 50% reduction in water supply. Some of the actions identified in the water shortage contingency pl an and currently implemented are: restricting landscape irrigation to two times a week, developing a la rge industrial customer incentive program that provides a monetary credit for a ll 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 billin g 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 lo cal water suppliers in California. The MOU identifies fourteen “Best Management Practices (BMPs) listed in Tabl e 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 a llotment, 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 hundredFinal 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 & industri al recycled water is only about 4% of the portfolio. It is interesti ng to note that LADWP expe cted to purchase more
than 60% of its water from the Metr opolitan 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 Supplie s for Multiple Dr y-Year Reliability 1, 2

Note: 1) LADWP 2005 Urban Water Manageme nt 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 functi on is to manage the supply of

water in Southern California. Its first f unction 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 th e 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, Rive rside, 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 wa ter 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 acr e-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 stor age 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 717,000 739,000 766,000 813,000Final 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 suppl y shortages including up to 50% reduction in its water supplies. The MWD also has a water surplus and drought ma nagement plan that outlines

various resources to minimize the possibility of severe shortage s 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 percen t 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 Supplie s for Multiple Dry-Year Reliability

Reference: Table II-8 Multiple Dry Year Supply Capability and Pr ojected Demands, The Regional Ur ban Water Management Plan of Metropolitan Water District of Sout hern 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 2,651,0 00 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 Replenishmen t Supplies 259,000 502, 000 473,000 155,000Final 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 an alysis above shows the following:

• The water demand increase due to this SOx RECLAIM project (consisting of installing/operating eleven we t gas scrubbers and two dry ga s scrubbers at eleven major

facilities to reduce 6.2 tons per day of SOx) is negl igible at 1,000 acre-feet per year compared to the water use of 6.37 million acre-f eet per year for the South Coast Hydrologic region. It represents 0.02% increase over the current wate r usage baseline.

• The potable water demands of this SOx RE CLAIM project are approximately from 1 2 1 1 acre-ft per year to 226 acre-ft pe r year which represent about 0.0 6 5 % - 0.11% of the potable water savings of 200 thousand acre-feet per ye ar estimated for the South Coast Hydrologic region.

• Table 11-4 provides a comparison of the wate r demand for SOx RECLAI M project with the water use/demand in California, South Coas t 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 perspec tive 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 Regi on (Year 2005 Urban Use) 6,370,000 MWD’s contract with DWR (State Water Project) 1,910,000

MWD’s entitlement from Co lorado 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 supplie d 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 dema nd 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. Th e Best Management Practices for conserving water focus in the area s 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, In dustrial sector only contributes approximately
15% to the overall water savi ngs required to meet the 20% reduction by 2020 asked for the Governor. Increased use of recy cled 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 ra te 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 r ecycled water suppliers. The substantial air quality and health benef its of the project far outweigh the pote ntial water impacts. However, in the spirit of carrying out abunda nce of caution in response to th e 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 estimat e 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/hea ters (40 ppmv, or to appr opriate 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/hea ters (40 ppmv, or to appr opriate 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 effec tiveness less than $50K per ton at the following proposed BARCT

levels: 5 ppmv for FCCUs 5 ppmv for SRU/TGTUs

Tier I level for boile rs/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 effec tiveness 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 boile rs/heaters (40 ppmv)

The results were presented in Table 12-1 us ing the information provided by ETS/AEC and NEXIDEA. In addition, staff adde d two more scenarios in the an alysis, Scenario 4 and 5. In Scenario 4, there would be no BARCT for SRU/TG s and Scenario 5 is to meet the minimum requirements in the 2007 AQMP. Please refer to Section 12. 3 4 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, st aff received feedback from WSPA and the refineries, and as a result, Scenario 3A was modi fied to not include costs associated with the

modifications for boilers/heaters to meet the ex isting Tier 1 BARCT at 40 ppmv. In addition,

modification to the cost effec tiveness was made to exclude any incurred costs and emission reductions from projects that have already be en 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 m illion (for boilers/heaters) = $630 million Emission reductions = 6.20 – 0.85 (for boilers /heaters) – 1.00 (reduc tions that already been achieved) = 4.36 tons per day Weighted average cost ef fectiveness = $15,845 per tonFinal Staff Report – Part 1 Chapter 12– Costs & Cost Effectiveness Analysis_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 125 November 2, 2010TABLE 12-1 – Costs & Cost EffectivenessFacility Refinery 1 Refinery 2 Refinery 3 Refinery 4 Refinery 5 Refinery 6Control Technology /VendorPresent Worth Value ($ million) 76 133 95 78 75* 110Scenario 1 - most stringentPerformance Level 98% 98% 98% 98%98%98%Emission Reductions (tpd) 0.60 0.30 0.35 0.240.941.01Cost Effectiveness ($/ton) 14,000 48,000 29,500 35,20010,70011,900BARCTBARCT/Start EFScenario 2 - consultantsPerformance Level 5 ppmv 5 ppmv 5 ppmv 5 ppmv 5 ppmv 5 ppmvEmission Reductions (tpd) 0.58 0.19 0.28 0.20 0.87 0.94Cost Effectiveness ($/ton) 14,437 76,211 36,636 42,103 11,600 12,849BARCT 13.38 lbs/MbarrelsBARCT/Start EF 0.26 (=2.29/52.06)Scenario 3A - staff'sPerformance Level 5 ppmv 5 ppmv 5 ppmv 5 ppmv 5 ppmv 5 ppmvEmission Reductions (tpd) 0.58 0.28 0.20 0.87 0.94Cost Effectiveness ($/ton) 14,437 >50,000 36,636 42,103 9,398 12,849BARCT 3.25 lbs/MbarrelsBARCT/Start EF 0.06 (=3.25/52.06)Scenario 3B - AlternativePerformance Level 7 ppmv 7 ppmv 7 ppmv 7 ppmv 7 ppmv 7 ppmvEmission Reductions (tpd) 0.57 0.14 0.25 0.19 0.83 0.90Cost Effectiveness ($/ton) 18,941 18,941 18,941 18,941 18,941 18,941BARCT 3.23 lbs/MbarrelsBARCT/Start EF 0.06 (=3.23/52.06)WGS - BELCO98% for 6 refineries0.36 lbs/Mbarrels0.01 (=0.36/52.06)5 ppmv for 6 ref - 5 new wet scrubbers and 1 existing wet scrubber5 ppmv for 5 ref - 4 new wet scrubbers, 1 existing wet scrubber7 ppmv with DeSOx catalysts*Refinery 5 revised its capital cost estimate from $70 million (Authority for Expenditures AFE) to$60 million in March 2010.Subsequently, staff revisedthe cost effectiveness in Scenario 3Afrom $11,600 per ton to $9,398 per ton.Final Staff Report – Part 1 Chapter 12– Costs & Cost Effectiveness Analysis_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 126 November 2, 2010TABLE 12-1 (Continue)EquipmentFacility Refinery 1 Refinery 2 Refinery 3 Refinery 4 Refinery 5 Refinery 6Control Technology /Vendor Emerachem WGS-TriMerEmerachem for 2SRUs & Tri MerEmerachem WGS-TriMer WGS-TriMerPresent Worth Value ($ million) 26 60 17 19 64 97Scenario 1 - most stringentPerformance LevelEmission Reductions (tpd) 0.13 0.20 0.15 0.04 0.07 0.31Cost Effectiveness ($/ton) 22,410 32,900 12,881 54,686 95,800 34,300BARCTlbs/hrBARCT/Start EF(=2.92/8.39)Scenario 2 - consultantsPerformance Level 5 ppmv 5 ppmv 5 ppmv 5 ppmv 5 ppmv 5 ppmvEmission Reductions (tpd) 0.13 0.17 0.15 0.04 0.06 0.29Cost Effectiveness ($/ton) 22,409 39,000 12,880 54,705 123,169 36,359BARCTlbs/hrBARCT/Start EF 0.46 (=3.89/8.39)Scenario 3A - staff'sPerformance Level Already met 1WGS 5 ppmv Emera 5 ppmv 2WGS 5 ppmvEmission Reductions (tpd) 0.13 0.17 0.15 0.29Cost Effectiveness ($/ton) n/a 39,000 12,880 >50,000 >50,000 36,359BARCTlbs/hrBARCT/Start EF 0.63 (=5.28/8.39)Scenario 3B - AlternativePerformance Level Already met 1WGS 10ppmv 1WGS 10 ppmv 2WGS 10 ppmvEmission Reductions (tpd) 0.13 0.13 0.11 0.27Cost Effectiveness ($/ton) n/a 48,606 34,695 >50,000 >50,000 39,147BARCTlbs/hrBARCT/Start EF 0.76 (=6.39/8.39)10 ppmv for 3 refineries. 1 already met reduction. 0 Emerachem. 4 new wet scrubbers.6.395.283.895 ppmv for 4 refineries. 1 already met reduction. 1 with Emerachem. 3 new wet scrubbers0.355 ppmv for 6 refineries. 3 with Emerachem. 5 new wet scrubbers98% for 6 refineries2.92Sulfur Recovery Units/Tail GasFinal Staff Report – Part 1 Chapter 12– Costs & Cost Effectiveness Analysis_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 127 November 2, 2010TABLE 121-1 (Continue)EquipmentFacility Refinery 1 Refinery 2 Refinery 3 Refinery 4 Refinery 5 Refinery 6Control Technology /Vendor FGT FGT FGT FGT FGT FGTPresent Worth Value ($ million) 1.4 20 15 16 64 21Scenario 1 - most stringentPerformance LevelEmission Reductions (tpd) 0.06 0.07 0.04 0.35 0.33 0.04Cost Effectiveness ($/ton) 2,395 30,948 46,906 4,903 21,071 57,416BARCTBARCT/Start EF 0.2 (=6.76/33)Scenario 2 - consultantsPerformance LevelEmission Reductions (tpd) 0.06 0.07 0.04 0.35 0.33 0.04Cost Effectiveness ($/ton) 2,395 30,948 46,906 4,903 21,071 57,416BARCTBARCT/Start EF 0.2 (=6.76/33)Scenario 3A - staff'sPerformance LevelEmission Reductions (tpd) 0.06 0.07 0.04 0.35 0.33Cost Effectiveness ($/ton) 2,395 30,948 46,906 4,903 21,071 >50,000BARCTBARCT/Start EF 0.2 (=6.76/33)Scenario 3B - AlternativePerformance LevelEmission Reductions (tpd) 0.06 0.07 0.04 0.35 0.33Cost Effectiveness ($/ton) 2,395 30,948 46,906 4,903 21,071 >50,000BARCTBARCT/Start EF 0.2 (=6.76/33)To Tier I level40 ppmv = 6.76 lbs/mmscft40 ppmv = 6.76 lbs/mmscft40 ppmv = 6.76 lbs/mmscftTo Tier I levelTo Tier I levelTo Tier I level40 ppmv = 6.76 lbs/mmscftRefinery Boilers/HeatersFinal Staff Report – Part 1 Chapter 12– Costs & Cost Effectiveness Analysis_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 128 November 2, 2010TABLE 12-1 (Continue)Equipment Coke CalcinerFacility Fac C Fac A Fac A Fac BControl Technology /Vendor WGS-BELCO Equip Mod-Cansolv WGS-BELCO WGS-BELCOPresent Worth Value ($ million) 25.3 1.7 8.0 17.3Scenario 1 - most stringent 5 ppmv-1 wet scrubberPerformance Level 5 ppmv (90%) 5 ppmv (>95%) 5 ppmv (>95%)Emission Reductions (tpd) 0.32 0.04 1.1Cost Effectiveness ($/ton) 8,642 17,596 1,594BARCT 0.03 lbs/ton cokeBARCT/Start EF 0.01 (=0.03/2.47)Scenario 2 - consultants 10 ppmv-1 wet scrubberPerformance Level 10 ppmv10 ppmv 10 ppmvEmission Reductions (tpd) 0.28 0.033 1Cost Effectiveness ($/ton) 9,902 5,556 1,896BARCT 0.11 lbs/ton coke 0.14 lbs/ton acid 0.14 lbs/ton acidBARCT/Start EF 0.05 (=0.11/2.47) 0.04 (=0.14/3.93) 0.04 (=0.14/3.93)Scenario 3A - staff's 10 ppmv-1 wet scrubberPerformance Level 10 ppmvmodification to 10 ppmv1WGS 10 ppmvEmission Reductions (tpd) 0.28 0.033 1Cost Effectiveness ($/ton) 9,902 5,556 1,896BARCT 0.11 lbs/ton coke 0.14 lbs/ton acid 0.14 lbs/ton acidBARCT/Start EF 0.05 (=0.11/2.47) 0.04 (=0.14/3.93) 0.04 (=0.14/3.93)Scenario 3B - Alternative 10 ppmv-1 wet scrubberPerformance Level 10 ppmv (80%) modification to 10 ppmv1WGS 10 ppmvEmission Reductions (tpd) 0.28 0.033 1Cost Effectiveness ($/ton) 9,902 5,556 1,896BARCT 0.11 lbs/ton coke 0.14 lbs/ton acid 0.14 lbs/ton acidBARCT/Start EF 0.05 (=0.11/2.47) 0.04 (=0.14/3.93) 0.04 (=0.14/3.93)10 ppmvnot applicablenot applicablenot applicable10ppmv - 1 WGS, 1 modification0.02 (=0.07/3.93)10 ppmv5 ppmvnot applicable0.07 lbs/ton acidSulfuric Acid PlantFinal Staff Report – Part 1 Chapter 12– Costs & Cost Effectiveness Analysis_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 129 November 2, 2010TABLE 12-1 (Continue)EquipmentFacility Kilns Coal Fired BoilerControl Technology /Vendor WGS-TriMer Limestone Absorber-BoldEco DGS or Limestone Abs - BoldEcoPresent Worth Value ($ million) 8.8 43.7 12.61,026Scenario 1 - most stringent 1 ppmv 1 ppmv 5ppmvPerformance Level 99% 95% (1-2 ppmv) 95% (5 ppmv)1,026Emission Reductions (tpd) 0.19 0.25 0.367.5Cost Effectiveness ($/ton) 4,988 18,893 3,81815,008BARCT 0.0058 lbs/ton glass 0.03 lbs/ton clinker 95%BARCT/Start EF 0.002 (=0.0058/2.51) 0.6 (=0.03/0.05) 0.05 (=1-0.95)Scenario 2 - consultants 1 ppmv 1 ppmvPerformance Level 99% 95% (1-2 ppmv)1,007Emission Reductions (tpd) 0.194 0.256.53Cost Effectiveness ($/ton) 4,988 18,89316,908BARCT 0.0058 lbs/ton glass 0.03 lbs/ton clinkerBARCT/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 11 WGS, 2 DGSPerformance Level 2WGS 95% (5 ppmv) 2DGS 93% (5ppmv)745Emission Reductions (tpd) 0.186 0.2486.20Cost Effectiveness ($/ton) 5,198 19,30013,160BARCT 0.03 lbs/ton glass 0.04 lbs/ton clinkerBARCT/Start EF 0.01 (=0.03/2.51) 0.74 (=0.04/0.05)Scenario 3B - Alternative 10 ppmv 10 ppmvPerformance Level 2WGS 90% (10ppmv) 2DGS 90% (10 ppmv)884Emission Reductions (tpd) 0.176 0.246.10Cost Effectiveness ($/ton) 5,487 19,94215,878BARCT 0.05 lbs/ton glass 0.05 lbs/ton clinkerBARCT/Start EF 0.02 (=0.05/2.51) 1 (=0.05/0.05)Not use in 2005Not use in 2005Not use in 2005Glass Plant Cement Plant($15,845 per ton if excluding emireductions of existing scrubber inthe cost effectiveness calculation.)Costs and Cost Effectiveness(including emission reductionsfor existing scrubber but notcosts since the scrubber wasinstalled for R1105.1)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 Anal ysis 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 th e previous consultant s and to review the feasibility and costs estimated by ETS/AEC a nd 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 estimat es using NEC’s recommen dations 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 cont rol. If NEC did not include the $1.88

million for additional PM10 control which woul d not be required under the proposed rule, staff estimated the total capital costs fo r 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 s hould 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 recommenda tion. 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 (mai ntenance 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 ex ample 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 Oper ating 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)(2 5 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 Scru bbers 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 – 44,25 6 7 45,12 1 0 12,78 3 2

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 SR U/TGs. However, if the oxidation catalyst technology was selected, the capita l costs would increase by a f actor 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 41,56 4 3Final 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 continge ncies added as recommen ded 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 (approximate ly 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 turnar ound 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 Ceme nt 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) 26,824 27,402 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 scrubb er. NEC recommended a different location than

ETS which results in an increase in the costs fo r ducting, substation additions, knife gate valve, and indirect costs. While NEC did not propose co st estimates for a large bore, open throat WGS, NEC agreed with ETS that wet gas scrubber w ould 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 r ecommended 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 refine ry (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. Follo wing 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 Sulfuri c 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) 2,833 3,255 8,768



### Coke Calciner

NEC recommended wet gas scrubbe r 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 th e cost effectiveness shown in

Table 12-6:

TABLE 12-6
Cost Effectiveness of Controls for Co ke 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 us ing NEC’s data for the pr oject, 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 calcin er + (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 wort h values estimated by ETS/AEC, NEXIDEA and

staff’s estimates based on NEC’s recommenda tions 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 No rton 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 fo r 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 ( 2,833 3,255 – 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 wi ll 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 fr om 2005 is equivalent to approximately 3.23 tpd RTC reductions due to the unused RTCs ava ilable 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 alr eady in place for an FCCU and a SRU/TGFinal 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 effectivene ss as required under H&SC §40440.11, staff proposal is compared to the most st ringent proposal propos ed by the consultants. Comparing the consultants’ proposal (including mo difications for fuel gas treatment system) and staff’s current proposal (not including modificatio ns for fuel gas treatment system ), the cost attributed to an additional 1.17 tpd incremental emission reduc tions was $377 million, which translated to an incremental cost effectiveness of $35K per incremental ton SOx reduced

. 68 This significantly high level of incr emental cost between the two options was the driving force leading staff to select the BARCT levels in Scen ario 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 requi rements for additional controls with economic impacts. The

BARCT levels in Scenar io 3 finally reflect “ ... emission limitation that is based on the maximum degree of reduction achievable, taking into a ccount 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 Effect iveness to Other Rules Adopted by the Governing Board

The weighted average cost effectiveness of st aff’s proposal is approx imately $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- 3 11 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 G overning 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- 3 11 Cost Effectiveness Comparison

2009 SOx RECLAIM ($/ton SOx reduced) Command-Control SOx Rule

Sulfuric acid plant: $2K per ton SOx reduced

Glass melting furnace: $5 K 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: $3 K 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 provi ded 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 L evels = (1997 Baseline x Growth Factor 2019 ) 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 Factor 2019 = Growth factor from 1997 – 2019 for each facility New BARCT Adjustment Factor = New BARCT Emission Factor / St arting 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 reduc tions for each of the scenarios described in Chapter 13 as follows:

Programmatic RTC Reductions = 11.77 - [Proj ected 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 si milar to the starting em ission factors. Staff estimated the projected remaining 2019 emi ssions, 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 re presented 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 Scenar io 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, st aff proposal is to reduc e 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 ac hieved under a command-andcontrol rule” as required by California H&S Code §39616.

In addition, staff proposes a eight-year implem entation 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 federa l annual average PM2.5 st andard by 2014. The remaining reductions will help the Basin to achi eve 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 20 08 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 th e turn-around for some refineries in the District. To ease the implemen tation 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 Reductions & Implementation_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 140 November 2, 2010TABLE 13-1 - RTC Reductions Estimated From 1997 BaselineAQMP Method - Projected to 2019Equipment TypeAudited97-98FiscaltpdGrowthFactor1997-20192019withgrowthScenario 3 - Staff's Proposal Scenario 4 - Intermediate Scenario 5 - AQMPBARCTAdjFactorReM ReDBARCTAdjFactorReM ReDBARCTAdjFactorReM ReDFCCUs5.681.00 5.680.06 0.34 5.340.06 0.34 5.340.26 1.48 4.20SRU/TG2.031.00 2.030.63 1.28 0.75 1.00 2.03 0.00 1.00 2.03 0.00Coke Calciner1.311.00 1.310.05 0.07 1.250.05 0.07 1.250.05 0.07 1.25Sulfuric Acid1.061.30 1.370.04 0.05 1.310.04 0.05 1.310.04 0.05 1.31Glass Melting Furnace1.711.45 2.480.01 0.02 2.450.01 0.02 2.450.01 0.02 2.45Cement Kilns0.532.58 1.360.74 1.01 0.350.74 1.01 0.35 1.00 1.36 0.00Boilers/Heaters6.111.00 6.110.20 1.22 4.880.20 1.22 4.880.20 1.22 4.88Total Major Equipment18.421.10 20.333.99 16.344.74 15.596.23 14.10Others1.061.11 1.181.181.181.18Total Remaining In Year 2019 WithGrowth (Minus 0.054 tpd reductions fromR431.1 & R431.2 for AQMP Method)5.125.87 7.361.1 x (Total Remaining)5.636.45RTC Reduction in Yr 2019 w 1.1 Factor =11.77 - (1.1xTotal Remaining)6.145.32For alternative shave, % reduction w 1.1 =(shave/11.09)55%48%RTC Reduction in Year 2019 w/o 1.19Factor = 11.77 - (1.19*Remaining)3.00% Reduction Across Universe w/o 1.1 tocompare w AQMP = (shave/11.78)25%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. Sta ff 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 (actua l emissions and RTC distributions) of the SOx RECLAIM market (11 major facilities hold 87% RT Cs 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 emi ssions 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 fac ilities if the RTC holdings are below their initial allocations provided to these faci lities at the start of the RECLAI M 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 allo cations 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 pr esented to our Governing Board in January 2010 is the commitment for staff to work closely with th e Western States Petroleu m Associations (WSPA) and its members in evaluating its alternative propos al. Staff held numerous meetings with WSPA and its members on this subject. As part of its pr oposal, on July 30, 2010, W SPA and the refineries proposed the 2005 baseline to be used to estimat e 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 da y) from any future shave. WSPA’s proposal

was obscure and did not show how the RTC reducti ons were related to act ual 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 Augus t 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 a nd RTC reductions from actual emission reductions. Unfortunately, WSPA offered very limited explan ation to staff. To keep the project moving in a positive direction, staff pr ovides the following initial comments on WSPA’s proposal.

SOx RECLAIM started in 1993 and the initial a llocations (or RTCs) pr ovided 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 contri buted 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” a nd thus even though RTCs carry the same unit (i.e. in lbs SOx) as actual emissions, they represent different “currenci es” than actual emissions. To fully demonstrate command-and-control equivalency due to the implementation of BARC T, due to the surplus, the

amount of RTC reductions should be more than the amount of actual emi ssion 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 member s calls for the calculation of the percent shave by taking the ratio of the actual emission reductions estimated off the 2005 ba seline emissions over the RTCs held in the market excluding any RTC convert ed from ERCs (1.98 tpd) at the inception of the RECLAIM program for which WSPA argued that shoul d be excluded from any future shave. Staff acknowledges that the 2005 year emi ssions were used as a baseline by the consultants to formulate their recommendation on feasibility and cost of contro ls 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 percen t reduction amounts to using two different “currencies” to compute a percent figure. This appr oach will not yield a resu lt 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 refine ries proposed to exclude RTCs converted from ERCs (1.98 tons per day) from any future shave which is incons istent with the RECLAIM program. As explained above, the RTCs converted from ERCs (1.98 tons per da y) is a layer of cushion added to the surplus. Integrating the shave through this la yer of surplus is one of the RECL AIM 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 emissi on budgets for the RECLAIM program. It was clearly the Board’s policy to achieve programmatic equivalency with command & control wit hout 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. Fu ture economic growth was included in the emission projection. The RTCs converted to ERCs have also been used by many of th e RECLAIM facilities in lieu of their emission reductions requirements u nder Tier 1 BARCT, whic h 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 th e 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 undergoingFinal 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 rati o 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 f acts plus the benefits incurred by the RECLAIM facilities utilizing such RTCs duri ng 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 th e 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 NoFinal Staff Report – Part 1Chapter 13 – RTC Reductions & Implementation_________________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 144 November 2, 2010TABLE 13-2 – Shave Adjustment Factors for Staff’s Proposal – 55% Shave in 2019Year2012RTCInventoryasofAugust29,200911major21others investors total10.21 0.73 0.83 11.77EstimationofAdjustmentFactorsforRule2002RTCsubjecttoshavefor11majorfacilities,3oftheremaining21facilities,andinvestorsRTCNon‐ShavedPortionRTCReductionforthefollowingyearRTCforShaveAdjustmentFactorfornextyearTOTAL(totalforshave+non‐shaved)StartYear2011 11.09 0.68 11.09 11.09+0.68=11.77EndYear2011 1.5 11.09‐1.5=9.59 9.59/11.09=0.865StartYear201211.09x0.865=9.590 0.68 9.59 10.27EndYear2012 1.5 9.59‐1.5=8.09 8.09/11.09=0.729StartYear201311.09x0.729=8.090 0.68 8.09 8.77EndYear2013 1.5 8.09‐1.5=6.59 6.59/11.09=0.594StartYear201411.09x0.594=6.590 0.68 6.590 7.27EndYear2014 0.32 6.59‐0.32=6.27 6.27/11.09=0.565StartYear201511.09x0.565=6.27 0.68 6.270 6.95EndYear2015 0.32 6.27‐0.32=5.95 5.95/11.09=0.5365StartYear201611.09x0.537=5.96 0.68 5.960 6.63EndYear2016 0.32 5.96‐0.32=5.635 5.635/11.09=0.508StartYear201711.09x0.508=5.635 0.68 5.635 6.31EndYear2017 0.32 5.635‐0.32=5.315 5.315/11.09=0.479StartYear201811.09x0.479=5.315 0.68 5.315 5.99EndYear2018 0.32 5.315‐0.32=4.995 4.995/11.09=0.45StartYear201911.09x0.45=4.99 0.684.99 5.67EndYear2019 06.100SummaryRTCHOLDINGS RTCsubjecttoshave Non‐shaved TotalStarting 11.09 0.6811.77Ending(Remaining) 4.99 0.685.67Reduction 6.10 0.006.10%reduction55.0% 0%Threeof21facilitieshaveRTCholdingslargerthaninitialallocationsbyatotalof0.05tpdTherefore,non‐shavedportionfor22facilities‐0.73‐0.05=0.68tpdTotalreductionin8years(2012‐2019)This table includes the following RTC Holdings: 10.21 tpd from11 major facilities, 0.05 tpd from 3 of the remaining 21 facilities, and 0.83 tpd from investorsFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 145 November 2, 2010 

## Chapter 14 – C omm 

## ents & Responses

Responses to WSPA’s Comments R eceived 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 co st-effectiveness numbers by each class or category of source, and that staf f should not pre-exclude the cost -ineffective scenarios of more than $50,000 per ton SOx reduced in estimating the weighted average cost effectivene ss for the project.

Response #1 The California H&SC §40406 does not specifically dict ate where in the calculation process staff

should exclude the cost-ineffectiv e scenarios. However, in re sponse to WSPA’s comment, staff estimated the weighted average cost effectiv eness for each class or category of sources regardless of each of the individual cost-effectiv eness numbers. Tables 1 and 2 below show the

costs and cost-effectiveness fo r each individual class or cate gory 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 includedETS/AEC’s costs for both tail gas units at Refinery 3. (2) NEC did not reestimate the costs for (i) the WGS for th e second unit of Ref 3, (ii) the Emer achem for Ref 1 of which the emission reductions were already achieved, and the Emerachem for Re f 4, and (iii) the WGS for Ref 5 since. This task was not in the NEC’s contract. To complete this analysis, st aff 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 21,992Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 147 November 2, 2010 

## Responses to INTERCAT’s Comme nts Received on October 10,

2010

Comment

#1Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 148 November 2, 2010 Comment

#2Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 149 November 2, 2010 Comment

#3Final 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 impact ing adversely to the FCC processing rates and yields or PM emissions from the refinery ESPs. Staff also appreciates the commenter for providing the information a bout the performance w ith INTERCAT SOxGETTER that 1) three refineries recently conducte d 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 throu gh the EPA testing protocols during the EPA Consent Decree testing program. Staff is in ag reement with the commenter that each refiner should conduct short term testing to measur e 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, orPM 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 testin g process, it would very likely demonstrate the proposed BARCT standard 5 ppmv level at a slig htly 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 part iculate matters in the ESPs. However, please note that SCAQMD Rule 1105.1 contain two standard s: (1) a filterable PM 10 standard of 0.005 grain per dry standard cubic foot of flue gas corrected to 3% O 2 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% O 2 dry, averaged over 60 consecutive minutes . The ammonia slip standard is to minimize the condensable particulate emissions fr om 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 con tinue 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 cataly sts in the ESPs, and minimizing the use of toxic

enhancers such as ammonia in the ESPs.

Response #2

The definition #72 in Rule 2000 – Genera l, amended May 6, 2005, states that “ SOx EMISSIONS means sulfur dioxides emitted .” The BARCT level of 5 ppmv pr oposed 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 m eet 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 reconc iliation 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 th e facility’s annual cap if the facility meets allFinal 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 informa tion 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 th eir FCCUs; 2) no additional pl ot space is required; 3) no increase in water consumption; 4) no steam pl ume; and 5) no increase in energy used and GHG associated with the use of SOx reducing additives.

Regarding the costs and cost-effectiveness, usi ng SOx reducing catalysts will reduce capital expenditures but not necessar ily annual operating costs. Staff estimates on costs and costeffectiveness for SOx reducing catalysts and WG Ss 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 SO x reducing catalysts is approximately $19K per ton (average of 5 refineries that can cost-effectively use additio nal SOx reducing catalyst s) to achieve 7 ppmv. With the competitiveness of the market and the improvement of SOx reducing technology, the cost-effectiveness numbers for SOx reducing ca talysts may improve, and the present worth values of using SOx reducing cata lysts may amount to only half the costs for installing WGSs as estimated by the commenter.

It should be noted that staff does not agree w ith the commenter that the use of WGSs would orphan the significant investment th at the refiners had made in th e ESPs. ESPs are required to
control PM10 emissions while WGSs are to cont rol SOx emissions. Further explanations are provided in Response #1 to WSPA’s commen t received from March 2010 – August 2010 under the topic discussing about whether or not there is stranded inve stment of Rule 1105.1.

In addition, staff does not agree with the comm enter that the use of WGSs will convert air pollutant into water pollutant. Va rious types of absorbents (e.g. ca ustic 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 su lfates can be collected and re used, 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 Dist rict that tested SOx reducing catalysts and achieved 7 ppmv in a 3-month period in 2008 to estimate the co st-effectiveness for SOx reducing additives shown in Scenario 3B of Chapter 12. Please note that sinc e this refinery did not use INTERCAT product in 2008, the costs of SOx reducing additives and the quantity need ed 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 tran sportation of caustic so lution 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 redu ced from 13.24 tons per day to 8.79 tons per day for the SOx RECLAIM project, and as an alyzed by CEQA staff, the transportation of additional NaOH would not pose an y new transportation hazards: 73

“All of the refineries (Facilities A through G) currently receive NaOH from local suppliers located in the greater Los Angeles ar ea. For the remaining fa cilities that do not currently use NaOH, but will begin using it, th e local suppliers are expected to be able to accommodate the additional demand. As is currently the case with existing NaOH deliveries, deliveries of additiona l NaOH would be made to each facility by tanker truck via public roads. NaOH is typi cally delivered in 6,000 gallon trucks, so the proposed project would not introduce any ne w 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

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_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 155 November 2, 2010 Response #1
Based on recommendations from its two technical consultants and informa tion from other glass melting furnaces elsewhere, staff concluded that T t oday’s BARCT for container glass melting furnaces is 5 ppmv outlet concentration, or 95% c ontrol or more. This BARCT level is achieved in practice at Saint-Gobain glass container faci lity in Seattle, Washington. In addition, achiev ing

this level of BARCT is cost-effective

. In an effort to determine costs, ETS provided equipment

vendors with flue gas flow rates, in let concentrations, and other ne cessary parameters. Flue gas flow rate is an important parameter in determin ing equipment size and costs for the WGS, wh ile inlet concentration is an important parameter in determin ing the amount of caustic sorbent needed to achieve 5 ppmv outlet SOx concentr ation and annual operating costs. The present

value for two WGSs (25-year life) estimated by ETS was $8.8 million, in which the capital costswere $1.90 million, and the annual operating costs were $0.44 million. ETS estimated a costeffectiveness of $4,988 per ton SOx reduced. A ssuming that Owens-Brockway was correct in stating that their inlet con centration were 200 ppmv-250 ppmv without the use of the dry scrubbers, and assuming that it would need r oughly 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 cons ervatively estimated to be $22.5 million and the cost-effectiveness would be $12,988 per ton. 74 A t $12,988 per ton , it would still

be cost-effective to control the SOx emissions from gl ass melting furnaces at Owens-Brockway to a BARCT level of 5 ppmv (95% control or more). Thus, the WGS is capa ble 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 ga s (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 pack ed bed scrubber recommended by ETS and by Manufacturer A, or an open-throat scrubbe r recommended by NEC, or a Cloud Chamber

scrubber as installed at Saint-G obain glass facili ty in Seattle.

• The purpose of SOx RECLAIM is to implement BARCT for SOx, therefore ETS and NEC did not discuss about “primary particul ate 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 scr ubbers upstream of the ESPs. Reducing the Trona used in the two dry sc rubbers to zero will substantially reduce the primary particulate loadings to the ESPs, save ener gy, 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 Ef fectiveness = $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 fa iled to address a variety of issues. This
is incorrect.

• Wet gas scrubbers for acid gas removal are lo w-energy scrubbers with pressure drop of about 5 in – 10 in. Removing the two dry scr ubbers 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 fa n in their equipment package to compensate for any potential pressure drop

.

• Owens-Brockway currently has a waste wate r treatment at their facility. OwensBrockway discharges waste water to LACSD. The facility has a permit discharge limit of 250 gpm and the current di scharge rate is below 100 gp m. A typical waste water

stream from a caustic sc rubber 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, pe rmitting costs etc. A dding 50% contingency

would result in a cost-effectivenes s 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 signifi cant since Owens-Brockway should not be increasing emissions due to the installation of WGS.

Response #3 Staff is committed to work with Owens-Brockway a nd 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

. P lease be cognizant that while NSR
issues related to NOx and SOx are covered in Rule 2005, NSR issu es 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 

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_____________________________________________________________________________________________ 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 glas s manufacturing should be the cont rols currently operating at your facility. However, the application of wet gas scrubbers still remains the recommended BARCT for glass manufacturing furn aces 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 billion 76

. SCAQMD records confirm that Owens-Brockway is the only glass contai ner facility in the

District.

Response #2

Control technology has improved over time. The dr y 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 concentra tion (95 percent control efficiency or more from the 2005 emissions baseline, 99% from the uncontrolled level assuming that the dry scrubbers operated at 80% contro l) and thus, should be consider ed as BARCT for SOx for glass melting furnaces. While these two consultants re commended different types of WGSs, they both

concurred that WGSs would be cost-effectiv e and staff concurs with the consultants’

recommendations. The two consultants both re commended keeping the existing ESPs in place for particulate control and placing the we t scrubbers downstream of the ESPs.

In addition, the proposed BARCT level for glass me lting 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 gl ass container fa cility, that demonstrates compliance with 5 ppmv SOx leve ls (96 percent control) via Tri-Mer’s Cloud Chamber scrubber. The furnace at Puget S ound 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 tec hnology, 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 Repo rt for Saint-Gobain, Seattle, Washington, Glass Melting

Furnace No. 5 with Cloud Cham ber 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 par ticulate matter and prevent excessive particulate buildup in the wet scrubbers. In addition, ETS pr oposed to remove the two dry scrubbers located upstream of the ESPs. Trona inje ction in the dry scrubbers would no longer be needed, and thus Trona leakage to the ESPs would drop to zero, a nd the particulate loading to the ESPs would be reduced significantly.

To put the problems occurred at Owens-Brock way and Ball-Foster Glass Container into perspective, staff provides the following explanations:

Owens-Brockway

Previously, Owens-Brockway operated three furn aces (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 emi ssions from the three furnaces are controlled by three ESPs located downstream of the semi-dry scrubber (any two ESPs ar e in operation at one time, while one ESP is standby.) One of th e furnaces (Furnace A, non-oxy fuel furnace) was shutdown in December 1996. During this period, th e exhaust temperature dropped, resulting in condensation buildup and corrosion within the E SPs. 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. C ondensation 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 (Cas e No. 4472-9) supports this belief:

“Prior to discontinuing the operation of Fur nace A, the temperature of the combined exhausts from Furnaces A and C, when mi xed 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. Conseque ntly, 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 we t scrubbers would now be locat ed 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.Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 169 November 2, 2010 Ball-Foster Glass Container

The problem occurred at Ball-Foster Glass Contai ner (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 scrubb er and increasing the particulate loading to the

scrubber. Staff believes that the excessive soli ds build-up in the scrubber system was due to failure to redesign the venturi wet scrubber to ha ndle the excessive partic ulate 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 re duces particulate matter emissions substantially and thus prevents particulate entrai nment to the packed bed scrubbers.

It should be pointed out that Owens-Broc kway 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, collect ed data, interviewed facility representatives and then independently ascertained that WGSs ar e technically and economical ly 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 Owe ns-Brockway’s comment letters and staff responses to the consultants for their input, and their i nput are incorporated in this response. 79

Second, the timing issue should also be mentione d. It has been almost two years since the consultant’s (ETS) analysis of the Owens-Brock way facility was finalized in December 2008. During this time, representatives from Owens -Brockway rarely participated in the SOx RECLAIM Working Group meetings or provided st aff 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 we re 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

_____________________________________________________________________________________________ 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 incorre ct assumptions and technical errors relative to ETS’s analysis as outlined below:

• (1 st bullet) The commenter incorrectly assumes th at 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 w ith two new WGSs downstream of the ESPs.

• (2 nd bullet) Owens-Brockway current setup shows that redundancy is needed for particulate

control but not for SOx contro l. Owens-Brockway operates tw o dry scrubbers and has three ESPs connected by piping/valves, but only tw o are in operation at any one time and one remains in standby mode. ETS recommended th e removal of the two dry scrubbers and the discontinue use of Trona, a ve ry 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 substant ially and reduce the need to use the stand-by ESP. Owens-Brockway operate s 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 contro l efficiency but not necessarily redundancy.

• (3 rd bullet) Additional pressure drops were a concern for ALG since ALG incorrectly assumed that the BARCT control configura tion recommended by ETS included both the two dry scrubbers and the two wet scrubbers. W ith ALG’s incorrect assumption, there would be additional pressure drops acro ss the wet scrubbers that woul d need to be taken into consideration. However, ETS recommended the removal of tw o 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. I n 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 ex tensive 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

.

• (4 th bullet) The three ESPs (two in operation and one st and-by) were designed to ensure that if one ESP experiences operational difficulties, th e 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 recomme nd the removal of the stand-by ESP, but recommended Owens-Brockway to keep one stand-by ESP to handle upset conditions, andFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 171 November 2, 2010 thus maintain the integrity of the two wet sc rubbers downstream of the ESPs. ETS did not view that building redundancy for SOx cont rol by adding a third sc rubber was necessary because monitoring the pH level and increasing the use of caustic may work as efficiently.

• (5 th 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.

• (6 th bullet) The commenter failed to specifically iden tify what foreseeable additional costs that the consultants might not include in their an alyses. 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.

• (7 th 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 mi nute (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 caus tic 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 faci lity’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 di scharge concentration limit for Selenium on Owens-Brockway’s industrial discharge perm it. Furthermore, staff estimated the

concentration of selenium that potentially could present in th e waste water stream of OwensBrockway facility based on their annual emission reports from 2002-2009. Selenium

concentrations in their waste wate r stream would be around 0.022 mg/L, 80 much less than the threshold set in CFR, Part 268 – Land Dispos al 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 additiona l 10 gpm waste stream that contains trace of selenium and other inorganic compounds. The consultant (ETS ) also allocat ed $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 a nd 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 providedfour 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.Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 172 November 2, 2010 1) “The liquid blowdown from the scrubbers c ould 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 evapor ate 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 prio r 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 signi ficant environmental impacts expected with the options quoted above. While the commenter critici zed Option 3 (the comme nts were based on the incorrect assumption about the continued use of dry scr ubbers and Trona injection), no comments were submitted relative to Options 1, 2 and 4.

• (8 th bullet) One WGS for a FCCU has been installed and is currently operating at a refinery in the District. The exhaust gas stream from th is existing WGS is expected to have similar characteristics (i.e. lower temperature, reduc ed 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 fede ral ambient air quality standards and a Permit to Operate was issued by the SCAQMD. If app lications for the proposed WGSs are submitted by Owens-Brockway, the WGSs scrubbers will unde rgo an equivalent or similar evaluation. Moreover, there is no evidence of po tential 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 sh ave. Owens-Brockway’s SOx emissions in 2005 were approximately 0.2 ton per day. Owens-Bro ckway indicated that th e control efficiency of their dry scrubbers was demonstrated at 90 per cent, but that they are operated at 75 percent to 80 percent. 82 If Owens-Brockway can operate their dry scr ubbers 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-B rockway 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 dayFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ 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 opera te 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 perc ent shave. The RTCs can be purchased from investors or from other SOx RE CLAIM 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 propos ed 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 e fficiency were considered as BARCT in 1994. Today’s control technologies routinely demonstr ate 95+% control efficien cies and can achieve control levels of 5 ppmv or be tter. Therefore, Owens-Brockwa y should not be included in the list of exempt facilities in Table 5 of the PAR 2002.

Response #6

Staff and the consultants 84 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 su fficient use of caust ic 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 spac e limitations should not be a problem. Both consultants visited the site, ev aluated the situation, and concu rred that space would not be a problem.

• Operational problems are site- and equipment-sp ecific, 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 th ey 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 ta ke 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 we re 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 NEXI DEA to Minh Pham on October 12, 2010.Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ 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 wit hout 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 th e language in subparagraph (f)(1)(Q) of Rule 2002, staff believes that the language, as currently stated, makes it cl ear 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 accord ing 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 al locations adjusted in accordance with Rule 2002, subparagraphs (f)(1)(I) and (f )(1)(J) at the Table 4 BA RCT levels, effective 2012.

Response #8

The background on Owens-Brockway’s furnaces and control equipment provided by ALG is

consistent with the information documente d 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 addi tion, staff knows of no installation in which a faci lity relies upon using dry scrubbers, dry ESPs, followed by wet scrubbers to achieve the emission reductions recommended by the consultants. However, sta ff 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 indivi dual comments are summarized as follows:

• Regarding the control efficiency of the dry scru bbers, it is interesti ng 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 ope rated at a 75 percent to 85 percent control efficiency. If the dry scrubbe rs are operated at 90 percent c ontrol efficiency level, then Owens-Brockway would emit approximately 0.1 ton per day and as such, would be in compliance with the proposed 55 per cent 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. Spec ifically, 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 leve ls at 96 percent contro l efficiency via Tri-Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ 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)

demonstrat ing 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 c ontrolling acid gas (SOx). In addition, the commenter’s

assessment about the control c onfiguration recommended by ETS is incorrect. The control configuration recommended by ETS (which wa s 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 1 st bullet under Point #4 of ALG’s assessment) The commenter assumes that three WGSs would be needed to correspond wi th 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. T hus, there is no need to inst all 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 re dundancy (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. la rger than $50,000 per t on) 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 2 nd bullet under Point #4 of ALG’s assessment) Additional pressure drops were a concern for ALG since ALG incorrectly assu med that the BARCT control configuration recommended by ETS included both the two dr y scrubbers and the two wet scrubbers. However, ETS recommended the removal of tw o dry scrubbers upstream of the ESPs, and to replace those with two wet sc rubbers 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 pr ovide the required energy. Manufacturer A did in clude the fan into their proposal, therefore the concern of pressure drop seems irrelevant.

• (Response to 3 rd bullet under Point #4 of ALG’s assessm ent) 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 Repo rt for Saint-Gobain, Seattle, Washington, Glass Melting

Furnace No. 5 with Cloud Ch amber 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.Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ 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 su bstantially the amount of particulate loading

to the ESPs.

• (Response to 4 th bullet under Point #4 of ALG’s assessm ent) There are several types of WGSs: 1) quench, vertical packed bed scr ubbers as recommended by Manufacturer A; 2) simple open-throat scrubbers as recommended by Manufacturer D; or, 3) fluidized rotating scrubber as offered by Manufact urer 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 tole rate up to 20 mg/Nm3 of insoluble particulate without clogging; and if the particulate is sol uble (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, pl ugging problem is not likely to occur. The SOx RECLAIM program does not require Owens-Brock way to install any particular type of scrubber. In fact, Owens-Brockway is encour aged to further conduct study and research to determine the type of WGSs and solvent that best fit their operati on and emission profiles.

• (Response to 5 th and 6 th bullet under Point #4 of ALG’s assessment) Please refer to Response #3 (7 th bullet). Owens-Brockway reported that the facility is currently sending wastewater to the LACSD and the City of Vernon to be treat ed 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 expect ed to mainly contain

soluble sodium sulfate that woul d result from using caustic solv ent 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, SCAQ MD 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 fo r this treatment inresponse 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 pa rticular facility if the problem

would occur if WGSs were installed. While the commenter criticized Option 3 (the comments were based on the incorrect assumpti on 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 brea kdown 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, 2008Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 177 November 2, 2010 • (Response to 7 th , 8 th and 9 th bullet under Point #4 of ALG’s assessment) There are hundreds of scrubbers operating across th e nation that currently utili ze caustic solution (NaOH, 50 percent by weight) as a scrubbi ng agent. The commenter has fa iled to provide evidence to support the claim that the use of caustic solution will create additional environmental impacts, other than what was already identifi ed and analyzed in the Draft PEA. While caustic solution is a very comm on 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 th ree WGSs are not needed and space is not a problem. They identified two different separa te 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 includ e contingencies, costs for additional ducting and valves for an alternative location; and th e commenter indicated that additional costs for CEMS upgrade were also needed. Including al l of the additional co sts suggested by NEC

and the commenter would not make the BARCT recommended by ETS cost-ineffective.

NEC concurred that the control costs for WG Ss 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 prob lem (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.Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ 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 b een submitted to the District. We understand that Staff has initially reviewed the information and s till 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 WS PA’s previous Rule 1105.1 cost-survey that showed implementation costs were 3-5 times (or more) gr eater than the preliminary cost estimates made by District Staff and District c onsultants. We believe the docume nted actual installation costs are superior to any pre-rule cost estimates.

The District should accept the cost data provided by the refineries and ack nowledge 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 a nd 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 a nd the costs that were the result of corporate decisions or those that extend to other facility operati ons (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 rela tive to the actual instal lation 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 li tigation 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 ma nufacturer (Hamon Research Cottrell) and same contractors (Jacobs Engineering/ Ham on Research Cottrell) during a short construction/installation pe riod from the mid of 2007 – mi d 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 cost s of the projects. In addition, all refineries selected to build extra redundancy to their ES Ps, and upgrade other systems (e.g. substation, NOx and SOx monitoring) that may not be direc tly related to the FCCUs. Furthermore, the market experienced a surge in st eel prices in 2008. Th ese facts together e xplain the differences in the costs estimated pre- and post- rule deve lopment by staff and AQMD consultants as well asFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 179 November 2, 2010 those that were provided by industry. Please al so note that all of th e cost figures submitted significantly varies with the costs incurred by Ch evron 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 m eetings 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 ot her words, based on the feedback received, the

installation of the SO x control technology under considera tion 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 Dist rict on March 5, 2010, one WSPA’s member cited H&S Code 39616(b)(2) – “A market-based in centive program ..... may substitute for current command and control regulations and future ai r quality measures that would otherwise have b een adopted as part of the district’s plan for a ttainment, and may be implemented in lieu of some or all of the control measures adopted by the district pursu ant 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 a ttainment, 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 progr am to pollutants listed under Chapter 10. Indeed, Section 39616 (b)(1) provides that the Distri ct 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 Distri ct has legal authority th at goes beyond controlling primary pollutants stated in Chapter 10. Chapte r 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 st aff 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 bu ilding block of PM2.5. Chemical speciation of PM2.5 samples indicated that in the South Co ast Air Basin 25% of the ambient PM2.5 is

attributed to contribution from sulfates. Furt hermore, SOx reductions ar e 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 t ons NOx). Therefore, considering the level

of NOx reduction needed to meet future ambient standards of PM2.5 and oz one 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 st andard 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 strategi es 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 furt her 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 equivale nt 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 s ubstantially from 1993 from 42 facilities to 32 facilitie s today with a very different em ission profile. Why can’t the

district use the most current emissions di stribution (e.g. 2005-2009) to estimate future RTC

reductions and demonstrate attain ment (or equivalency)? Why is there a need to base the estimation of RTC reductions on 94 or 97 baselin e 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 code s to conduct periodic BARCT reassessment and demonstrate equivale ncy with command-and-control rules which would otherwise be developed as a result of BARCT reassessment:

“...achieve an equivalent or gr eater level of emission reduc tions at an equivalent or

lower cost as would have been achi eved 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 appl y BARCT when it is available and costeffective, and demonstrate equivalency with co mmand-and-control rules. Staff selected to use

the 1997 baseline to be cons istent with the NOx RECLAI M 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 fu ture 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 Marc h 5 and again on April 7. Whil e the allocation data report forwarded to us by District Staff does not provid e the level of detail we requested, we have begun a detailed review of the information. Havi ng this information is a key to understanding how a reduction in RTC allocations can affect comp liance costs and, indeed, the RTC market.

Response #4
WSPA is correct that the SOx shave methodol ogy 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 th rough several comment letters. Staff believes that the proposed methodology for SOx RE CLAIM, as in the ca se 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 in itial allocation data that was highly resource intensive to produce. At the March 5, 2010 meeti ng 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 explaine d that the information requested would be a very resource intensive undertaking a nd would take several weeks to assemble. To that end staff spent a considerable amount of time assembling th e allocation tables and meeting with each of the refineries, explaining their particular al location profile line-by-line or equipment-byequipment specification. The leve l of detail and the form of the information presented was, in part, staff’s effort to be sensit ive to WSPA’s concerns regardi ng 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 cemen t 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 opera ting 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. Usi ng 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 bo ilers/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 RECLAI M 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 notFinal 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 unu sed 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 (r eleased by the District on J une 17 2010) has called into question the cost analyses previous ly performed by the District and its consultants. It appears

that the ultimate conclusion of Norton Engineering is thatthe District’s RECLAIM costeffectiveness analysis should be revised.

Response #6 It is true that the Norton Engi neering 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 consultant s in this revised draft staff report.

Comment #7 While NEC only relied upon the a nalysis and data provided by the initial cons ultants, NEC found numerous instances where the District’s init ial 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 cont rol technologies have not yet been proven or tested in the petroleum refinery and cement industry areas. However, th ese are not “unproven or untested” in the sense of not being commercially available or in use in other applications. Th ese types of controls

would be better characterized as transferrable technologi es. 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 cons ultants severely underestimated construction, labor and materials costs. NEC ha s 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 TIC 89 for four of the five plants agreed reasonably well with that of the original estim ates, 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 show n in Chapter 12. The pr oject costs based on the

89 TIC = Total Installed CostsFinal 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 ra ise the District Staff’ s cost estimate for th e District’s proposed shave significantly above the current level of $745 million.

Response #8 When one considers the capital investment to co mply with staff’s proposal there is about a 21 percent cost differential between Norton Engin eering 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 di fferent approaches along with newl y acquired data. In contrast, staff has difficulties in jus tifying the cost figures from WS PA 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 tec hnology is technically feasible, achieved in practice and cost-effective; therefor e, it directly affects BARCT

determination and should cause th e District to rethink its pr oposed reductions in the RTC

market.

Response #9 As mentioned above, the cost differential between the two sets of cons ultants is within the margin of error of the analysis conducted and in staff’s view doe s 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 confid entiality and anti-trust concerns, facilities and vendors in the final report by No rton Engineering are de-identifie d. 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 Engi neering may not be necessary after all.

Comment #11 WSPA requests the District to re -estimate the cost e ffectiveness 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-identif ied). The aggregated cost estimates provided by WSPA on April 7, 2010 include: 1) Total co mpliance 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 fo r 25% shave; 2) Distribution of th e 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 tota l 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 s cenario and $28,165 per ton for 25% shave scenario for refinerie s as of April 7, 2010.

Response #11 Staff is very sensitive about th e costs estimated by WSPA, and pl an to work in concert with

WSPA to understand WSPA’s estima te of almost 3 billion dollars for the proposed project. It seems that WSPA may include other costs ab ove and beyond the scope of SOx RECLAIM. While the refineries can modernize and upgrade thei r facilities to respond to market demand and other regulatory requireme nts, 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 comp liance 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-tradab le RTC accounts starting

in 2015 to be made available in th e event the market price of “dis crete” RTCs is higher than $50 K per ton. More specifically, in the event that the SOx RTC prices for “d iscrete” RTCs exceed $50,000 per ton based on the 12-month rolling average, staff will re port 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 Governin g 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 no t include any portion of

non-tradable/non-usable RTCs th at are designated fo r previous complian ce 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 “t o the next Refinery Committee meeting.” These representatives will be given the opportunity to provide thei r insights on the impact the Staff proposal will have on water supply and wastewater treatment. Distri ct Staff will also explore

the extent to which the water demand can be offset by groundwater from wells owned andFinal 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 pu rveyors attended the meeting c onfirmed that recycled water

would be made available for the refineries in a n ear future. In addition, CEQA staff has sent the Draft Program CEQA document to the representa tives 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 co sts provided to them by the refineries, $900 per acre-foot recycled water) in thei r 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 constructi on, project emissions or any other environmental impacts. We encourage the Dist rict 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 em issions or any other environmental impacts. Based on this information, as well as informati on from other sources, staf f did and will continue to do their best to address the program’s effects as specifically and comp rehensively as possible, so that subsequent activities at RECLAIM faciliti es 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 streamli ne the permitting process for i ndividual 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 exis ting Title V/RECLAIM permitted equipment, may involve changing the existing proc ess units by adding process vessels, enlarging existing process vessels and replacing one type of chemical solution with another ty pe. These activities will be subject to various District re gulations, particularly Regulation XIII – New Source Review, Rule 1401 – New Source Review of Toxic Air Contami nants, 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-app roved Rule 1315, we suggest that the SCAQMD begin implementation of this elemen t 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 releas es to the flares, NSR and Subpar t Ja applicability to flareFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 186 November 2, 2010 modifications, Best Available Control Technol ogy (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. WS PA 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 st aff received from the refineries directly. Furthermore, WSPA’s estimat es did not reflect the 55 % shave scenario that staff currently proposed. Staff identified thr ee scenarios in WSPA’s estimates that were substantially different from the c onsultants’ 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’ es timated 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 tonFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 187 November 2, 2010 

## Responses to WSPA’s Comment s Received on July 14, 2009

• BARCT, Cost Effectiveness Analys is, and RTC Reduction Estimates

Comment #1 A methodology for making the BARCT determina tion and calculation of the SOx reduction should be developed by the Dist rict, and understood by the stakehol ders, prior to conducting any analysis or any study. Staff must stay c onsistent with the 2005 NO x shave methodology. The identification of baseline year, starting emission factors, control factors, etc. has been lacking.

Response #1 The methodology for BARCT determination and RT C 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 Worki ng Group meetings since then.

BARCT Determination SOx RECLAIM program is requi red 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 achie ved under a command-and-control rule”

To fulfill this requirement, staff has followed a traditional, transparent, BARCT determination methodology that is similar to the methodol ogy 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 demons tration 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, ener gy, & economic impacts by each class or category of source.”

Thus technology that is both feas ible and cost effective must be considered BARCT even they are not yet proven achieved-in-practice. A feas ible technology is a te chnology that has been previously installed and operated successfully at a similar type of so urce, or has practical potential for application to the so urce, i.e. has been successfully applied to simila r sources with similar gas stream characteristics.

The potentially proposed BARCT levels for 7 categor ies 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. Pleas e refer to the Preliminary Draft Staff ReportFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 188 November 2, 2010 dated April 3, 2008 and subseque nt 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 Apri l 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 fac ility-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. Th e objective of this refinement was to optimize the effectivene ss of the subsequent staff propos al 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 agreem ent in principal with the desire to stay

consistent with the 2005 NOx shave met hodology, designing a shave methodology that is workable for the SOx RECLAIM program, but rema ins fair and equitable is not a trivial and simple task.

To use the 2005 NOx shave methodology, staff inve sted tremendous amount of time and efforts
to recover the 1997-1998 emissions baseline and th e starting emission factors in 1993. Using the 1997-1998 emissions baseline and the 1993 starting emi ssion 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 show n 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 prematur e technology recommendations by the District. The attempt to identify these candida te 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 recommenda tion. 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 re levant information to the stakeholders. Part I, II and III of the Staff Report reflect the progression in the though t and evaluation processFinal 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. Sp ecifically, Part III of the Staff Report has utilized the information presente d 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 ba seline, growth factor) to estimate the RTC reductions. This approach is consistent w ith 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 eva luating 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 prac tice as retrofits? WSPA’s opinion: No

o Is technology available and feasib le for retrofits? WSPA’s opini on: Feasibility must take into account environmental, economic and energy impacts, based on this NO

o Do manufacturers offer guarantees for achi eving proposed emission levels? WSPA’s opinion: Guarantee letters were all prospective - contractor has not issued, or presented evidence of, guarantees at the recommende d levels and corresponding demonstrated equipment operation functioning und er those guaranteed letters.

o Is retrofit technology cost-e ffective? WSPA’s opinion: No

o Based on the above criteria, could a command a nd 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 stri ngent BARCT level than the SCAQM D? Staff’s response: No. Because of the severity of ai r pollution its seventeen (17) million residents have to endure, SCAQMD usually sets the most stringent BA RCT emission standards in the nation. The more stringent BARCT standards are needed fo r 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 achi eved 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/TGTU s (Sinclair Refinery, Casper Refinery.) The proposed technologies (e.g. wet/dry gas scru bbers) are commercially available, feasible to achieve 5 ppmv in all 7 equipment applica tions identified by staff, and they are cost effective to implement.

• Is technology available and feasible for retrof its? Staff’s response: Yes. Wet/dry gas scrubbers are commercially avai lable, feasible and cost eff ective for retrofits. Emerachem oxidation and absorption catalyst technology is co mmercially available, has been used inFinal 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 tran sferable to refine ry 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 re fineries, as well as the Govern ing 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 a nd control BARCT rule have been proposed in the absence of the RECLAIM program? Staff’s res ponse: Yes. It should be noted that if a command and control BARCT rule would be propos ed, 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 com pared to other SOx sources in the basin.

Substantial reductions in SOx emissions have b een made from refine ry flares but are not properly credited in the 2007 AQMP.

Response #4 Staff acknowledges that significa nt progress has been made in reducing SOx from refinery flares. However, significant additional re ductions are needed above and beyond those committed in the 2007 AQMP to meet the fede ral and state 24-hour PM2.5 standard. A reduction of 3 tons per day is achievable for SO x RECLAIM facilities ta ken from the following categories:

• 1.76 tons per day RTC surplus for RECLAIM so urces (11.76 tpd available RTC – 10 tpd of 2005 emissions = 1.76 tpd RTC surplus)

• Refinery boilers/heaters can reduce approximately 0.89 tpd re duction 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, th e 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 sour ce-by-source basis. In additi on to that, staff asked the consultants to conduct a facility -by-facility analysis. Conduc ting 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 s ite specific analysis to ensure th at the proposed technology can be implemented cost-effectively at each facil ity. The BARCT analysis (e.g. use a top-down approach in the selection for BARCT, use of di scount cash flow (DCF) me thod in calculating the cost effectiveness factor) was clearly writt en in the contracts’ Statement-of-Work.

There are at least two reasons that make the f acility site specific analysis possible for SOx

RECLAIM but not fo r NOx RECLAIM:

• The universe of sources in SOx RECLAIM is mu ch smaller than the uni verse 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 pl ot space. The main control technology for SOx sources is a wet gas scrubber for which a unit-specific anal ysis 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 pr inciple 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 subst antiation (e.g. six months of operation at a certain performance level). This was not done for any of the source ca tegories examined for the refinery. In fact, it cannot be done for the SRU systems pr oposed as BARCT because none have been used in refineries, much less sulfur plants.

Response #7 A technology does not have to be achieved-in-pr actice 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 sc rubbing technology however is proven achieved-in-practice, and commercially availa ble 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 incl ude all of the true associated costs, including additional equipment needed to provide additional heat and steam. These gaps have created a signifi cant problem for evaluating potential emission reduction technology applications, their cost effectiveness, and also the logi stical applicability to specific facilities. It is inappropriate for the Distri ct 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 co sts. This procedure is common to all cost estimates. The commenter did not specifically indi cate in what applications the additional heat and steam were needed for, so the comment cannot be addressed .

Comment #9 Analyses of plot space require ments 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 soluti on significantly understates potential costs and cost effectiveness.

Response #9 The commenter has incorrectly characterized the contra ctors’ 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 Statem ent-of-Work, the contractors were required to

conduct field visits at ea ch 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 th eir analysis just to the vendo r supplied equipment (e.g. wet gas scrubbers) but extended their analysis to cove r ‘the total applicatio n’ and they thoroughly discussed the plot space issues wi th the facilities. As stated in the contractors’ reports:

“Infrastructure items were discussed extensiv ely. These include available areas for a scrubber for the FCCU, room on existing pipe racks, piling, Elec trical Substation......., control systems, steam, water, available sewer allocation.....”

Comment #10 The “average cost effectiveness” ratio presen ted in the staff report is not an appropriate representation of the cost effe ctiveness of available SOx re duction technologies and has the potential to mislead policy makers. A clear cost-effectiveness thre shold should have been established upfront. An incremental cost effe ctive analysis should have been completed to provide a clear relationship between incremen tal SOx reductions, cost and the associatedFinal 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 pr ocess 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 St ep 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. averag e 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 effectiv eness factor across a cl ass of equipment (e.g. $25K per ton for all FCCUs’ wet gas scrubbers); a nd the average cost effectiveness factor for the entire SOx RECLAIM project (e.g. $17K per ton) were shown in Appendi x III-A of the Draft Staff Report.

Staff did not select a clear threshold for cost e ffectiveness at the time the draft staff report was released. After further consideration, staff se lected a cutoff threshold of $50K per ton as a means of removing the least cost-effective cont rol technology recommended by the consultants and optimizing the effectiveness of the most recent staff proposal.

At the time the draft staff report was released, st aff 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 consu ltants’ 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 st aff considered environmental, energy, economic impacts in any of the proposed scenarios. Un til 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 c onducting additional analysis for e nvironmental, energy and economic impacts to support the proposed BARCT determinati on 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 emi ssion levels. It is unlikely that under command and control, all of these BARCT proposals would become rules - particularly for those source categories that ha ve only a single facility. It would be more appropriate to have a mix of more and less aggre ssive levels equivalent to a programmatic BARCT to allow the RECLAIM program to be viable.

Response #12 Staff disagrees with the commenter. Wet ga s scrubbing achieving 5 ppmv – 10 ppmv outlet concentrations is not a technology forcing technol ogy. It is a mature, co mmercially available, and achieved-in-practice technol ogy for many of the affected equi pment categories (e.g. FCCUs, SRU/TGs, glass furnace, coke calciner).

For SOx RECLAIM, staff estimated a program matic 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 base d on the feasibility of wet gas scrubbing technology.

Comment #13 The reliance on guarantee letters pr ovided by the manufacturers is faulty and should not be relied upon to validate or support th e emission reduction sustainability.

Response #13 Guarantee letters provided by the manufacturer s are only one piece of information that staff relied on to judge the feasibility of the control equipment. In a ddition to the guarantee letters,
staff also relied on achieved-in- practice information, source test s data, CEMS data, and expert consultants’ analyses. Furthermore, the sustai nability of the emission reductions relies heavily on how the facilities operate and maintain their control equipment. If staff develops commandand-control rules, good engineer ing practices (e.g. annual mainte nance, annual testing) would normally be crafted in the rule requirements to a ssure continuous compliance with the BARCT levels and guarantee the achievabili ty 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 alte rnative feasible and available control technology

Response #14 In late August 2008, staff developed a testing protoc ol for de-SOx catalysts with the participation of WSPA and the refineries. Only one of the re fineries 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 #15Final 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 SC AQMD: 1) clarification of how certain emission factors (starting and new) for FCC’s, SRU’s a nd boilers were derived fo r individual facility process units, 2) facility specifi c data/calculations be sent dire ctly 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 factor s (starting and new) for FCC’s, SRU’s and boilers were derived for individual facility pr ocess 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 provide d in the Working Group meetings on July 30, August 13, and August 27, 2009

• Facility specific data/calculations were e-maile d 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 wa ste 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 installa tions), and an increased wastewater load to Publicly Owned Treatment Plants (POTWs) as hi gh as 440 million gallons per year (40 million gallons and an assumed eleven systems t hat would discharge to a POTW).

Response #16 The above estimated water usage and wastewat er 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 Questionnai re to gather informat ion on the current usage of water, the current amount of wastewater and solid waste genera ted, and the existing practice (e.g. ground water capacity and cu rrent pumping rate, recycled water usage) at the 11 top emitting facilities. The f acility’s responses to staff’s Surv ey 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 fo r the 11 facilities is 18,842 m illion gallons per year. This project would require 364 million gallons water pe r year. This impact reflects an estimated
2% increase in water demand from these facili ties 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 numbe r 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 gene rally 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 technol ogy. As any other cont rol technology, wet gas scrubbing also has its own advant ages as well as disadvantages. Regardless of the disadvantages cited, many facilities in the U.S. and in the Dist rict have chosen to install and successfully operate wet gas scrubbers to cont rol SOx and particulate matter from various types of stationary sources. Clearly, those faci lities believe the advantages of the technology outweigh any disadvantages. As written in the Module 3A re port, the consultants objectively commented on both the advantages and disadvant ages 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 haz ards that accompany it are typically manageable in a refining environment. In a ddition, 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 Unit s, 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-mont hs 1-hour CEMS data (a total of 10,386 records). The average concentration of this 18-months period of ope ration was 1.2 ppmv at 0% O2, well below the proposed BARCT level of 5 pmv. In addition, ther e is a wet gas scrubber installed and operatedFinal 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 da ys and a performance source test result) was listed in Appendix III-D of the draft Staff Report.

Comment #19 It is inappropriate for the consul tants to make a BARCT recommendation.

Response #19
Staff did not view the consultant s’ action as inappropria te. As shown in th e 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 w ith this level as required by the contract. However, they also concluded that a level of 5 pp mv 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 shoul d not be viewed as inappropriate. During the process of formulating its final BARCT proposal, st aff 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 fi nal decision on what are the appropriate BARCT levels.

Comment #20 In the report, the contractors st ated 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 pur ely based on technical information. The consultants conducted a detailed engineering eval uation 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 vi able control technologies, starting with the most effective control technology, and make recommendations to the District on various technologies that coul d potentially be used to achieve additional emission reductions, on various concentration target s that could be achieved with each technology, the estimated em ission reductions, the multimed ia pollutant impacts (e.g. water, waste), energy impacts of the techno logies, 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 a nd other impacts, the consultants recommended aFinal 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 tr eatment techniques. As mentioned in previous responses, in formulating its BARCT proposal, staff carefully evalua ted the consultants’

recommendations and introduced several refineme nts 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 quota tions and published cost studies. Because there are only five FCCU s in the Basin, and because the estimated present worth of implementing the proposal for FCCUs alone is $493 m illion, 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 th e Statement of Work, the consultants conducted site specific analysis for each FCCU at the six re fineries and gathered costs information for each

individual FCCUs from the manuf acturers. As shown in the fi nal report of Module 3A, the consultants included the following it ems 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/demobilizati on, typically 10 % of DFL

o Overtime/productivity factor , typically 12 % of DFL

o Freight and shipping, typical ly 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 assi stance, depends on project

o Front-end engineering desi gn, depends on project size

o Project management, depends on project size

o Design development allowance, 10% of total

o Contingency, 25-40% applied against th e 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 th e cost effectiveness factor. This costFinal 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’ re port, section H:

“Wet gas scrubber equipment footprints and space requirements for the FCCUs and the SRU/TGTUs are shown in the confidential appe ndices for each refinery where measures

have been selected. These specifications have been co mpared with the plot plans provided by the respective refineries, and wher e 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 us eful 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 parti al "credit" against the purchase of fresh catalyst. The initial purchase price of the metal is only actually r ecovered 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 al so included the costs for catalyst change ($420,000) quot ed 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 in stall 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 cont rol 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 c onsideration as part of the staff analysis.

Comment #25 Inadequate information to subst antiate the 5 – 10 ppm perform ance of the wet gas scrubbers designed for the SRUs/TGTUs. The lack of subst antiation 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 appea rs to include higher variability, making a comprehensive review all that more import ant. WSPA requested and did not receive specific data used by the consultant s to arrive at the cost effective co nclusions 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 estim ates – all at no risk whatsoever to themselves. This is particularly true of this source categor y where the proposed BARCT vendors have no experience with installation in refineries, which ma kes 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 fo r Refinery #3 but Emerachem pr ovided the consultants with a guarantee letter and the consultants also consider ed 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 curr ent 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

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 201 November 2, 2010 

## Responses to Chevron’s Comment s Received on July 14, 2009

Comment #1 It is inappropriate for the Dist rict to aggressively pursue SOx shave for PM2.5 attainment. The current trend of PM2.5 is declin ing and does not warrant a SOx sha ve 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 code s to conduct periodic BARCT reassessment and demonstrate equivale ncy with command-and-control rules which would otherwise be developed as a result of BARCT reassessment:

“...achieve an equivalent or gr eater level of emission reduc tions at an equivalent or

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

It should be noted that SOx is a significant bu ilding block of PM2.5. Chemical speciation of PM2.5 samples indicated that in the South Co ast Air Basin 25% of the ambient PM2.5 is

attributed to contribution from sulfates. Furt hermore, SOx reductions ar e 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 cont rol strategies committed in the 2007 AQMP for meeting the 2015 annual PM2.5 standard are necessa ry 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 part s 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 20 10, currently revised to 55%) that staff estimated for the SOx RECLAIM uni verse as a whole is st ill 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 pur sues the command-and-control approach.

Staff however is sensitive to the costs of the current proposal (approxim ately $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 reductio ns 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 wast e were not discussed. Capital investment to manage additional volumes of water demand, wast ewater and solid waste generated were not included. In addition, the proposal did not incl ude the complexities of attaining necessary permits (e.g. NPDES Discharge Permit.)

Response #2 Staff is in the process of analyzing the enviro nmental 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 tota l 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 ye ar, or 46 million gallons per day). Ground water pumping capac ity is available for fo ur out of six refine ries. Three out of six refineries have used recycled water. All 6 re fineries are not subject to any cap from the water suppliers. The water suppliers in dicated to staff that they can supply the additional amount of water to the refineries. In addition, the increas e in total water demand is 80% below the current CEQA threshold of 5 million gallons per day for si gnificance. However, in a spirit of taking abundance of caution, CEQA staff classified this pr oject as significant in terms of potable water demand. Please refer to the Program Environm ental 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 increas e in wastewater discha rge in excess of 25% would trigger a discharge permit revision. Howeve r, 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 ca n 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 wast e depending on how effectively the scrubbers are in controlling particulate ma tters. The consultants estimated about 2,560 tons per year increase. The current FCCU fines classified as non-haza rdous waste generated from the six refineries are approximately 3,348 tons per y ear. This 67% increase may be trucked to

several cement facilities in and around the basi n (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 quot ed below, the consultants did include additional capital costs for waste and wastewater treatment . In addition, the consultants did include additional annual operating costs fo r additional water, wastewater treatment, and solid waste disposal.

“Added charges for waste or wastewater trea tment equipment are included in equipment

costs unless treatmen t is performed outside of the boundary limits for the control measure. In these cases, the treatment co sts have been calculated according to the treatment requirements and s ite-specific unit costs prov ided by the refineries.”

Comment #3 Emerachem technology is not a proven technol ogy. The contractor report does not offer any strategy for dealing with the concentrated SO 2 stream captured and released later from the catalysts, therefore this tec hnology cannot be considered as SOx reduction technology.

Response #3 It is true that Emerachem technology has not ye t been installed and used in a refinery, and

therefore there is no achieved-i n-practice data available. Ho wever, this argument does not negate the feasibility of this technology in a refinery applica tion. For BARCT, additional time can be provided to allow technology to mature in refinery applications. Furthermore, in addition to the Emerachem technology, the consultants pr ovided 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 effectiven ess 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 (d ata from 2 WGS vendors were considered),

• Additional 3 rd stage Claus units resulted in about 20 tons/year reduction for SRU#10 and

SRU#20 and a cost effectiv eness of $24K per ton.

If for the sake of an argument, the current scenario (Emerachem fo r SRU#10 and SRU#20) is replaced with other scenarios (3 rd 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 overa ll cost effectiveness of the proposed overall program.

Comment #4 The shave methodology was not transparent, was di sclosed 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 Di strict’s staff and ag reed 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 meth odology that will work for the SOx RECLAIM market and is fair and equita ble is not a trivial task. To use the 2005 NOx shave methodology,

staff invested tremendous amount of time and effo rt to recover the 1997-1 998 emissions baseline and the starting emission factors in 1993. Us ing the 1997-1998 emissions baseline and the 1993 starting emission factors, staff estimated the cont rol 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 expect s the proposed shave methodology to continue being refined throughout the rule making process.

It should also be noted th at the shave methodology was disc losed sooner than in the NOx RECLAIM rulemaking effort in 2004-2005.

Comment #5 The methodology for development of emission fa ctors was not clear in the report, and the background for some of the initial emissi on factors was not clearly explained.

Response #5 The following information was provided to WSPA and the refineries:

• Clarification of how certain emission factor s (starting and new) for FCC’s, SRU’s and boilers were derived for individual facility pr ocess 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 provide d 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 w hat 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 RE CLAIM, staff is required by the H&S codes to conduct periodic BARCT reassessment and demonstr ate equivalency with command-and-control rules which would otherwise be develope d as a result of BARCT reassessment:

“...achieve an equivalent or gr eater level of emission reduc tions at an equivalent or

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

As a result of this BARCT reassessment and e quivalency demonstration, staff estimates that the SOx RECLAIM program can be amended to provi de 6.2 tons per day em issions 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 guarant ees. 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 selec tion process outlined in Part III of the Staff Report. The BARCT selection process included fi ve 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 imp act analysis for environment, en ergy and economic, and 5) select BARCT. Vendor guarantees are important informati on for Step 2. In eval uating the consultants’

recommendation for BARCT and ar riving 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 ad equate information have been provided to substantiate the proposed BARCT for all s ource categories.

Comment #3 An analysis of the impact of the proposed shave on the RECLAIM ma rket has not been conducted. Because of the potentially dramatic impact that this shave will have on the RECLAIM SOx market, Tesoro supports a phase d 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 strategi es for the 24-hour PM2.5 standard, it analyzed the input of the standard as part of the 2007 AQMP. This analysis revealed th at 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 analys is for the SOx RECLAIM program. To reduce the impacts to the SOx market, staff is in agreem ent 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 phase d 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 technol ogies are not adequatel y considered in the consultant reports or in the St aff reports. The report bundles all the measures into an “average cost effectiveness” ratio. This “average co st effectiveness” ratio is not an appropriate representation of the true cost of the SO x 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 de mand, wastewater discharge levels and hazardous waste generation resulting from use of wet gas scrubber technology. Furt her 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 con cerning 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 refi neries 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 startin g emission factors

FCCUs Starting emission factor = Total emissions (lbs/year) / Total th roughput (barrels/year) = (6,033,327 lbs/year) / (115,893 thousand barr els refinery feed ) = 52.06 lbs/Mbarrels

Sulfur Recovery Units Starting emission factor = Total emissions (l bs/year) / Total hours operation (hours/year) = (1,122,050 lbs/year) / (133,764 hours/year) = 8.39 lbs/hrsFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 207 November 2, 2010 Boilers/Heaters Starting emission factor = Tota l 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/t on)/(396 thousand ba rrels 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/t on)/(396 thousand ba rrels 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 Equi p/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 a nd 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 Repor t (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 sma ll 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 sour ce categories and do not yet meet the BARCT standard should be required to take the BARCT adj ustment. Facilities that do not operate FCCUs should not be responsible fo r 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. Th e preliminary draft Staff Report released in 2008 focused in finding BARCT and emission reduc tions from the top el even 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 examini ng two alternatives: 1) provide an alternative percent shave for these facilities, or 2) not shave thes e facilities at all. Fo r 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 surp lus 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 comple te, yet the District scheduled for implementing the SO x 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 implem entation date should be moved back to 2014 to enable facilities time to pursu e these major modifications

Response #2 Staff proposed a first shave of 1.5 tpd at the en d 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, ther efore 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 f our 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 recen t developments in this rule making process. Paramount did not have an opportunity to participat e in the consultants’ study and evaluated the findings along with major refiners. Paramount suggests that a concerte d outreach effort be conducted to ensure that all impacted facili ties are given the opportunity to understand and

comment on the District ’s SOx shave proposal.

Response #3 The recent developments were all publicly noti ce. The Request-for-Pr oposals 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 pr esented to the Governing Board at two public meetings on July 11, 2008 and Se ptember 5, 2008. There are subsequent public consultation meetings, workshops, and working group meetings held where the consultants’ recommendations and suggested amended proposals were further discusse d. There were ample opportunities for the commenter to participate. However, staff did not receive any comments, suggestions, or indications of interest from th e 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-facili ty confidential basis and cannot be discussed with the commenter. Staff did send copies of the consultants’ non-conf idential 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 Draf t Part I Staff Report - RECLAIM SOx

WSPA appreciates the opportunity to comment on the "Preliminary Draft Staff Report Sox RECLAIM Part I Allocations, Emissions & Cont rol Technologies" (the "Report"), and we appreciate your patience while we were addres sing the other priorities that you had established (e.g., the RFP for the contractor project, FCCU SO x 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 them selves, and we need not summarize them in this transmittal. However, there are a few overa rching issues that we would like to specifically call to your attention:

1. The draft Report references 2007 AQMP Contro l 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 overvie w of existing control technologies and suggests new, potentially feasible emission rates or lim its, it does not provide deta il regarding the process

the District will use to identif y new 2010 facility annual allocati ons, 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 exac tly how proposed revise d allocations and the proposed shave will be calculated. Only once the pr ocess has been agreed to should the District move ahead with reassessing the BARCT levels.Comment #1Final 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 moderniz ation (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 facili ty modernization analysis with this effort. WSPA is concerned about the potential fo r blurring the distinc tion 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 Re port 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 PM 10 or PM 2.5 levels; rather, it must desc ribe and provide evidence for how SOx emissions contribute to ambient pa rticulate matter concentrations and how the anticipated SOx emission reductions will affect ambient air quality.

4. The "Proposed BARCT Levels and Emission Reductions" sect ion of chapters three through

nine includes detailed conclusions with respect to the applicabili ty of various emission control technologies and the resultant BARCT levels for the various source categories in the SOx RECLAIM program. These conclusions are prem ature and unsubstantiated, and their inclusion in the report is not appropriate give n that the District is planning to hire one or more expert thirdparty contractor(s) to conduct th orough engineering evaluations a nd cost estimates of potential SOx emission reduction technologies. WSPA is ve ry 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 belie ves 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 a nd understand two or more separate and likely conflicting documents. WSPA has tried to presen t its detailed comments in a way that can serve as a useful guide for rewriting the draft Part I Re port, and hopes that Distri ct staff take advantage of our suggestions in that manner.

Again, WSPA appreciates the opportunity to subm it these comments on this important effort.

We ask that our detailed comments and this transm ittal letter be included in the record for this rulemaking. WSPA looks forward to working with th e District as this effort progresses, and we look forward to commenting on future drafts of th e Part I and Part II Staff Reports for this rulemaking, as well as on any proposed rule amen dments and other related regulatory materials.Comment #3Comment #4Comment #5Comment # 2Final Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 212 November 2, 2010 Please do not hesitate to contac t 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 comm ents, 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 Administ rative Records of this amended rule. This approach is taken

to reduce the bulk of the detailed comments/re sponses portion of the Draft Staff Report. First, staff would like to direct WSPA to the lega l basis of this rule ma king effort described in

Section 1.1 of the Draft Staff Re port – Legislative Authority. Secondly, with all due respect, staff disagrees with the sequence of appro aches 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 cont rol 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 alloca tion shave while maintaining the integrity, equity, and operational characteristic s 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 SO x 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 shav es. The concept of facility modernizati on, if used, may onlyFinal 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 significa nt role in this rule amendment effort.

Response #3 Please refer to Appendix 5 of the 2007 AQMP for th e 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 Respons e #1. The first three steps were presented in Part I of the Prelim inary 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, indepe ndent, 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 informa tion 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 Record s of this amended rule. This approach was

selected to reduce the bulk of the detailed comm ents/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 1 st 

## , 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: 2 nd Round of Comments on RECLAIM SO x Shave Staff Report Part 1

Dear Ms. Pham

BP appreciates the opportunity to comment on th e draft Part 1 of the staff report for the RECLAIM SOx shave. I provided some initial comments on this report back on April 29 th

. 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 th e 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 operate d 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 un it 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:

SO 2 Removal . The concentration of SO 2 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) 670-5493Comment #1Final 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 sy stem 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 sugge sting that SO2 was reduced as a result of the installation of a wet ESP (specifically desi gned for particulate a nd acid mist removal, not SO2). Any apparent SO2 reduction was likely coincident with this change but due to something else. The likely cause of inaccuraci es 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 th e 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 ne cessarily support the conclusion that the Wilmington calciner em ission 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 informa tion 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 fo r 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 hi gher 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, s hould not be explored in the 3 rd -party engineering analysis in Part II of the sta ff 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 commen ts, do not hesitate to call me at (714) 670- 5493 or reply to this e-mail.

Sincerely,

Miles Heller Air Issues SpecialistComment #2Final 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 Cansol v scrubbing system installed at Cherry Point Refinery’s Sulfur Recovery Units.

Staff acknowledges the informati on provided by BP that 1) the Cansolv scrubber has been designed to a level less than 250 ppmv, 0% O2, currently requi red by NSPA Subpart J/Ja or MACT II, and 2) is subject to a mass annual lim it of 135 tons per year, translated to 150 ppmv SOx, as BP. However, staff believes that it is not uncommon for a syst em to achieve levels below the designed levels. This fact is supported by the following examples:

• Two Cansolv scrubbers were designed for a FC CU and a FCU at Valero’s Delaware City Refinery. The designed outlet SOx concentr ation is 25 ppmv. Th ese scrubbers have been in operation for more than a year, and have actually achieved le vels 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 lo wer 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, a nd as such, will not remove this section. However, staff will

add a footnote to reflect the curr ent non-operational status of th e 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 Poin t 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 di scuss 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 scrubbe rs/wet ESPs for the calciners at Cherry Point Refinery accurately. The information pr ovided in the Preliminary Draf t 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 No rthwest 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 Effici ency (%), and Emission Rate (lbs/ton) The control efficiencies (98% - 99%) for Wilm ington’s coke calciners were based on actual outlet concentrations (27 – 52 ppmv) and inlet concentra tion (2700 ppmv). The control efficiencies (96.9% - 97.5%) fo r Cherry Point Refinery’s c oke calciners were based on permitted outlet concentration (35 pp mv) 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 co ke 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 addi tion, 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 pot ential lower BARCT level, sta ff strongly believes that BP should improve the performance of its contro l 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 1 st 

## , 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 th at I had them review. Thanks. Sue

Valero Delaware City Refinery Comments:

On page 1, in addition to Valero DE City, Moti va DE City is liste d. The Motiva entry is a duplicate. We are the old Motiva DCR. Th e 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 Al kylation Unit. I'm also not sure what the 65% reduction is referring to. The two re generative WGS units on the FCCU and FCU here in DE City were designed to reduce em issions by 99% at the FCU and 97% from the

FCCU.

Page 3 mentions inlet flow volume to the WG S. 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 sent ence 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 Na tural Resources and E nvironmental Control (DNREC)’s Division of Air Waste Management to cl arify 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 in dicated 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 a nd DNREC, staff has:1) deleted the duplicate entry for Motiva in Table 3-3; 2) made a clarifi cation 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 over all facility emissionFinal 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 fl ow rates for FCCU and FCU in Paragraph 3.3.2.3 of the Staff Report; and 5) included additiona l 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 F CCU 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 F CCU 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 Co mments Received April 29 th 

## , 2008

Rhodia Inc. provided comments and edits on Chapte r 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 ed its in the newly revised versi on of the Draft Staff Report.



## Responses to Rhodia’s Comment s Received November 25th, 2008

Comment #1 State law prohibits the Distri ct from setting BARCT levels wit hout considering the relative environmental and economic impacts on each affected source category. The Draft Report fails to make any findings at all concerni ng (1) the relative cost-effectiv eness of requiring the proposed SO2 controls at a sulfuric acid plant like Rhod ia instead of requiring more reductions from sectors responsible for greater PM2.5 and/or SO 2 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 imposi ng more aggressive contro ls 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 SO 2 controls on other sectors ma y cause less overall adverse economic impact than imposing those controls on Rhodia. For example, requiring additional reductions from highly emissive di rect sources of PM2.5 very we ll 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 smal l source of PM2.5 in the South C oast 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 ma y be less economically burdensome and/or more effective at producing PM2.5 attain ment by 2015. Accordingly, the Draft Report fails to provide a complete BARCT analysis.

Response #1 Staff recognizes that for a BA RCT 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 resu lts provided in the subject report is not the BARCT assessment but rather input for the sta ff to generate a recommended BARCT for the various equipment subject to SOx RECLAIM.

Comment #2 Since the District began its effort to investigat e and redefine BARCT for SO x from sulfuric acid plants and other sources, both th e credit markets and the broade r economy have suffered major downturns. Financing for major pr ojects is extremely difficult to secure, and most economic analysts predict that these cr edit issues will extend into 2009 and potentially 2010. The Draft Report makes no mention of these changed econom ic circumstances, and fa ils to discuss the potential impacts of tightening BARCT levels at a time when sour ces could find it difficult or impossible to complete the re quired 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 transpir ed 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 goa ls as presented in the 2007 AQMP.

Comment #3 AQMP Control Measure CMB-02 is a measure de signed to secure appropriate SOx reductions pursuant to RECLAIM, primarily (as the AQMP desc ribes) from refineries. It is not a control measure designed to achieve PM2.5 reductions require d for District wide attainment. While the District certainly has an interest in achiev ing PM2.5 attainment in the South Coast Air Basin, Control Measure CMB-02 makes no mention of re quiring 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 th e Basin, not disproportionately from a handful of SOx RECLAIM sources.

Response #3 The staff report will address th e 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 in stalled 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 approximat ely $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 opera ting 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 Dr aft Report’s cost effe ctiveness 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 changi ng BARCT, Rhodia strongly recommends that the District take the PDSR off the December calend ar, ask its vendors to document the sources for all of the cited cost data, and work with Rhodi a to resolve the data discrepancies before moving forward.

Response #4 The consultant has conducted a very thorough analys is with respect to the cost analysis of the subject equipment. However, gi ven the very low cost effectiven ess derived by the consultant theFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 222 November 2, 2010 costs would have to be several-fo ld greater than assessed in order for the cost-effectiveness to no longer being attractive.

Comment #5 The Draft Report assumes that Rhodia could in stall a new caustic scru bber as soon as 2011. Rhodia estimates that, if it were required to install a new scr ubber, 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 scr ubber installed at Rhodia may not be available to help PM2.5 attainment until 2012 or later, dependi ng on when the Dist rict approves the BARCT revision. The Draft Report fails to address the relative costs and benefits of requiring SO2 emissions reductions that would not yiel d PM2.5 reductions until those years, nor does it

address whether reductions in other secto rs 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 ti me needed to install control equipment.

Comment #6 In the first paragraph of page 4 of the Dra ft Report, we would recommend adding the following underlined language: “Historica lly double absorption plants ha ve 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 conducte d 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 incl ude the language in the subject re port. 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 Repor t. In the confidential section of the Draft Report

Response #7 The consultant corrected the facility id entification as indicated by the commenter.

Comment #8 Finally, though Rhodia provided extensive comment s and edits to the last draft of the PDSR, none of those comments appear to have been incor porated 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 b een 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 stricterFinal 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 29 th 

## , 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 prematur e, 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 ac tually 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 me ntion of this essential topic.)

WSPA notes that the revised draft RFP for the thir d-party contractor project mentions that the Part II Staff Report will include "... a disc ussion 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 recomme ndation 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. Becaus e we would expect a similar level of complexity with regard to SOx, the discussion s regarding process cannot wait for a Phase II Staff Report. We should not delay those discussions any fu rther – 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 amen dment. 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 faci lities warrants some di scussion and analysis. In particular, there wo uld be interest in knowing whethe r or not any facilities have ceased operations, and, if so, why they did.

Response #2Final 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 Repor ts presented to the AQMD Governing Board

on an annual basis in March. The most recent re ports 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 woul d be outside of this proposed SOx RECLAIM

amendment.

Comment #3 WSPA understands that BARCT reassessments fo r 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 t echnology 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 timi ng for this process (e.g. as ex peditiously as practicable) is required by both the federal an d 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 ame nding 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 it em 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 partic ulate matter (PM2.5). Reducing SO x is very important since it would help the Basin to meet the annual PM2.5 standa rd in 2014, the 24-hour PM2.5 standard in 2010, and ready to face a pot ential 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 de tailed information regard ing this phenomenon. The commenter is referred to such documents as the Appendix V of th e 2007 AQMP for more details on this subject.

Comment #5 The value of the target SOx reduction in the fin al version of CMB-02 is "2.9 tons per day" (and that was a change from the initia l 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 minimu m target emission reductions are expected to be 2.9 tons per day (~ 3 tpd) from 2010 through 2014 and are expected to remain constant afterFinal 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 th e feasibility to incorporate the concepts of Control Measure MCS-01 - Facility Modernizati on, to achieve reductions beyond 2014. If needed, staff will discuss the con cepts in Part II of the Staff Report.

Comment #6 It would be appropriate to include discu ssion and analysis of the following topics:

• The appropriateness of using CY 2005 as a "baseline" year.

• The methodology for calculating CY 2005 emissi ons since RECLAIM facilities are found in both calendar year and fiscal year cycles (i.e., there are both C ycle 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 operat ing facilities compared to third-parties who do not operate facilities. This information goes to establishing an appropriate compliance margin, and determining how deep a hypothetica l shave would cut into facility operations.

Response #6 Staff provides the following explanations:

• The development process for the amended SOx RE CLAIM 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 th e “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 accord ing to the same reporting protocol in Rule 2012 for SOx (e.g. major SOx sources must repor t emissions on a daily basis and process SOx sources must report emissions on a quarter ly basis.) Following are the reporting emissions group by compliance year (e.g. Em issions for compliance year 2002 means emissions reported from January 1, 2002 – D ecember 31, 2002 for Cycle 1 facilities, and July 1, 2002 – June 31, 2003 for Cycle 2 faciliti es. 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 pe r day emissions are the emissions reported for 2005 calendar year. The difference in 2 tpd be tween year 2002 & 2005 is mainly the result of shrinkage in SOx universe fr om 41 facilities since the star t of the RECLAIM program to

33 facilities in 2005 incl uding 12 facility shutdowns, 8 incl usions and 4 excl usions 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 to tal 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 cal culation in order to deri ve the correct product: 9.92 tpd x 93.95% x 80.79% = 7.53 tpd (f or the top 11 facilities) 9.92 tpd x 95.46% x 81.09% = 7.68 tpd (for the top 12 facilities, wh ere Saint Gobain Containers Inc has ceased operation).

Comment #8 WSPA believes that SOx allocations, which are he ld 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 Appendi x A to provide information (R ECLAIM Trading Credits) that is held by entities other than RECLAIM facilities.

Comment #9 Notwithstanding staff's efforts in this regard, WS PA believes that the disc ussion of potentially applicable control technologies must be a work product of the third-party contractor study that the District has proposed. The discussion a nd analysis of control technologies should be included in the Part II Staff Re port – not in this Part I.

It is both premature and inappropriate to presen t this list of candi date potential control technologies as being proposed t echnologies. The candidate contro l technologies wi ll 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 differenc e 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-exclusive 92 . 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 enha nced SRU/TGU efficiency w ith 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 technolog ies would be used in combina tion. 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 pr oposed 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 contro l technologies "would be em ployed to generate at least 3 tpd" suggests that the staff has already reached import ant conclusions regarding the potential BARCT reassessments and the amount of the potential reducti on of SOx allocations, respectively. Given the facts that the proposed third-party engineeri ng 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 t ons 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 cond ucted during the development of Part I of Staff Report and was provided in the April 3 and April 30 Worki ng Group Meetings. A subsequent estimate of emission reductions (6.5 tpd from the 2005 baselin e inventory) were provi ded by the third-party

contractors.

Comment #12 WSPA submits that the definition of BARCT is critical to this curre nt effort. BARCT is not BACT or LAER. BARCT applies on a retrofit basis and it must consider envir onmental, energy and economic impacts.

Response #12 Staff agrees with the commenter. However, it s hould 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 scr ubbers. 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 differenc e was that the BACT assessment has not been conducted for 8 years, not taking into recent adva ncements on control technologies. In addition, BARCT may anticipate future technological development.

Comment #13A Although WSPA recognizes the precursor relations hip 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 clea r and understandable rela tionship 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 th e 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, th ere needs to be some discu ssion 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 abo ve 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 eva luating potential SOx reduction technologies rather than using BARCT, as discusse d earlier in the staff report.

As stated previously, the prelimi nary draft Part I repor t 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 qualit y 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. Th e District is required to establish BARCT for this proposed SOx RECLAIM rule amendment as di scussed earlier in the Staff Report. BARCT would more likely be more stringent than the levels presented in RACM/RACT.

This Staff Report incorporates other documen ts 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 ba sis to develop the Clean Air Fine Particle Implementation Rule.

Comment #15 WSPA suggests that the staff report should list th e SOx facilities that have exited RECLAIM, and should indicate the reason for th eir 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 re ports published annually in March for this information. Typically plant clos ure is the result of several factors. Staff believes that discussions on plant closures, or facilities opt-i n 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 implemente d in the future?).

The statement assumes that advancements in contro l technology are occurri ng 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 incor porate the goal of expeditious emissions reductions. The sentence could report a more accurate num ber – 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 techno logies are “constantly” being improved. Rather staff is alerted at technology advancements, or re trospectively leads back to ascertain if control technology improvements warranted a BARTC asse ssment. Either approaches recognized progress made by the regulated industry, ve ndors 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 be en 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 a nnual allocations previous ly given to the NOx RECLAIM facility were further reduced by approximately 20% to reflect BARCT.

Comment #17

WSPA recalls that the 2003 alloca tions 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 bein g 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 establ ished the declining Tier 1 a nd Tier 2 allocations. BARCT is undergoing a reevaluation in this Staff Repor t 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 docum entation regarding the bas is 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 evalu ating the potential outcome of the BARCT

reassessment and SOx-shave.

As previously stated, there needs to be an expla nation 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 thei r respective analyses.

Response #18 The paragraph written in Section 1.4 correctly stated the inform ation presented in the Control

Measure CMB-02.

Staff first conducted an analysis for emissi on reductions in 2006 during the development of

Control Measure CMB-02 which resulted in a minimum of 2.9 tpd (a pproximately 3 tpd) emission reductions. Staff conducted a follow-up analysis in April 2008, re sulting 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 Worki ng Group Meetings. Expert contractors conduct a third independent analysis of emission reduction s and cost effectivene ss 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 mainta in 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 in corporate 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 revi ew 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 appl icable to a parti cular 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 em ission reductions that can be achieved. The third party

contractors will conduct their ow n engineering assessment on control technologies, and cost estimates to assist staff in making the fi nal 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 resu ltant cost-effectiveness, as re ported in the "literature", are usually for uncontrolled sources. The reports are rarely applicable to s ources that are already well-controlled, as is the case for facilities in the South Coast Basin.

Generally speaking, reliance on cost or cost-effecti veness 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 ot her cases, site-specific engineering estimates need

to be made because this entire BARCT reasse ssment exercise has to focus on potential retrofit

installations.

Response #20 As pointed out in previous respons es, 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 equi pment, it cannot be assumed that such installations have been determined to be cost effective. Many inst allations of emission control equipment have nothing whatsoever to do with cost-effectiveness cons iderations – rather, they might be part of negotiated Consent Decrees, they might be based on need to prov ide emissions offsets, etc. Where any determinations regarding cost-effectiveness migh t have been made, and when those determinations are quoted in the Staff Re port, they need to be documented.

It is premature to suggest any definitive conclu sions with respect to the amount of SOx emission reductions that might be expected. If various control technologi es are ultimately determined to be feasible and cost effective, then the result ing reductions will be used in calculating the specific amount of the allocati on 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 st aff in conducting detailed cost estimates for this rule amendment and the results will be pr esented in Part II of the Staff Report.

Comment #22 The discussion in the preceding paragraph should re flect 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’ anal yses will be summarized and presented in Part II of the Staff Report.

Comment #23 WSPA believes that the 12 ton per day value repres ents SOx allocations, not actual emissions. We also note that not all of th e allocations are held by RECLAIM facilities (some allocations are held by third-party invest ors, 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 com pared to those held by investors for both current and future years because the amount of al locations 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 RECLAI M Audit Report for the 2002 Compliance Year”, dated March 5, 2004, the actual emissions for co mpliance 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 ba sis. 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 fa cilities 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 repr esents allocations not emissions.

Response #24 In the NOx universe, 87% of the total emissions (24.02 tpd out of 27.61 t pd for compliance year 2003) are generated from the top 16% (54 out of 346 facilities) of the f acilities. Yet the NOx shave is divided equally (by perc entage) across the NOx universe. Therefore, similarly in the SOx universe, even though 95% of the total emi ssions (9.47 tpd out of 9.92 tpd) is generated from the top 12 facilities out of 33, the SOx RT C reductions will probably be divided equally (by percentage) across the SOx unive rse. As indicated in Control Measure CMB-02, however, the shave may be divided equally to 33 facilities, or may be restrict ed to specific facilities. AsFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 233 November 2, 2010 indicated in Part III of the Dr aft Staff Report, additional analys es will be conducted to provide

more information on how the RTC reductions shoul d 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 emissi on projections include the effect of allocation shaves. The precursor relationship of SOx to am bient PM should not simp ly be described as a "given" because there is no foundation fo r this claim in the staff report.

Response #25
The future estimated emissions for 2014 a nd 2023 (11.7 tpd and 11.8 tpd, respectively, without allocation shaves; and 8.8 tpd a nd 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 s hould 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 fo r 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 (an d, perhaps, misleadingly) suggests that a 3 ton per day (the correct value is 2.9 tons per day) reduc tion in SOx allocations is a virtual certainty. It is not – primarily because th e 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 ju stified on the basis of available retrofit technology, cost effectiveness, et c. Further, it should be noted that other source categories in Table 2-2 might be reasonable candi dates 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, s ubstantiated by staff’s analysis in CM CMB-02 and the analysis in Part I of Staff Report. The co st 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? (Som e analysis and discussion is needed.) There needs to be some discussion regarding why th e analysis was cut off at twelve facilities.

There needs to be some discussion of the reason fo r, and implication of, in cluding 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 valu e 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 regardi ng the selection of 2005 as the baseline year.

Response #30 As presented in the April 3 Working Group Meeti ng (slide #4), the 2005 emissions were selected

to be used in this rule amendment because th ey are within the range of emissions from other current years. The emissions from these t op 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 th e 2005 NOx RECLAIM amendment.

Comment #31 There should be some discussion regarding the char acterization of a source as "major", and it

should be noted that this descri ption 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 a ssociated third-stage separator (used to reduce filterable PM in the FCCU flue gas stream ente ring 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, Fi gure 3-1 is a generic flow diagram that was never intended to show every single piece of equipment included in theFinal Staff Report – Part 1 Chapter 14 – Comments & Responses

_____________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 235 November 2, 2010 FCCU at each refinery. Any components wh ich would complicate the reductions of SOx emissions should be captured in the third party consu ltants’ analysis.

Comment #33 An electrostatic precipitator and an SCR unit (where one is employed) occupy considerable refinery plot space, and limit th e potential use of other systems such as wet gas scrubbers. The title of the Figure should be "Typical Fluid Catalytic Cracki ng Unit". A block representing expander turbines should be added because thes e are common. The block representing SCR should be deleted or labeled as "Opt ional", because SCRs are uncommon.

Response #33 See Responses #32.

C

omment #34 RECLAIM allocations were not issued to proce ss 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 f acility according to the methodology described in

Rule 2002.

Comment #35 The average value for the three years, 2005, 200 6 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 audite d 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 19 97 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 Di strict 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 th e 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 ne eds to be considered when evaluating BARCT –

other considerations are environmen tal, energy and economic impacts.

WSPA is not aware of any basis for the statement implying a hypot hetical increase in capacity, and a corresponding need to upgrade any control devi ce. 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 regul ations, not EPA regulations. The facility’s SOx allocations are the summation of all allo cations estimated for each SOx source/process category at the refi nery. 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 on ly commercial availability technologies but not the technologies in development or at the res earch phase, and will evaluate BARCT considering environmental, energy and economic impact s as governed by federal/state rules.

The commenter may not be aware of any increas e 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 hav e been the Tier 1 shave target, not what was actually bei ng 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 Di strict – 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 We st 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 – Reduc tion of PM10 and NH3 from Fluid Catalytic Cracking Units , November 3, 2003.

BP, 2001. BP Exploration & Oil Company, Amoc o 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.

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____________________________________________________________________________________________ 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 SO x RECLAIM Facilities

Facility ID Facility Name Cycle E m i ss i ons (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 tota l 33 facilities listed in this table. Th e 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 dayFinal 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 fo r 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 I NDUSTRIES 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, SH ELL 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 HoldingsFinal 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 ENVIRONM ENTAL 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 10.08Final Staff Report – Part I Appendix A – 2005 SOx RECLAIM Emissions____________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 243 November 2, 2010TABLE A-3RTCs Available for RECLAIM Market from Shutdown FacilitiesFacilityID NameShutdownComplianceYearInitialAllocations2010+2010+Holding asof 8/26/2010IYB RTCAvailable toMarket(lbs)IYB RTCAvailable toMarket(tpd)6281US GOVT,MARINE CORPS AIRSTATION,EL TORO 2000 1,892 0 1,892 0.006394 ANAHEIM FOUNDRY INC 1996 7,782 0 7,782 0.019141 CANNERS STEAM CO INC 2007 8,596 0 8,596 0.0112912LIBBEY GLASS INC200471,816071,8160.1018984ANCHOR GLASS CONTAINER CORP1994136,0160136,0160.1940196GUARDIAN INDUSTRIES CORP.200771,882071,8820.1060942GAF BUILDING MATERIALSCORPORATION 1994 70,052 0 70,052 0.1067945 GREAT WESTERN MALTING CO., INC. 2002 125,326 0 125,326 0.1779397OWENS-BROCKWAY GLASSCONTAINER INC1996102,4450102,4450.1499588 DOMTAR GYPSUM INC 1999 8,572 8,572 0 0.00106797SAINT-GOBAIN CONTAINERS, INC.2004235,5580235,5580.32108701SAINT-GOBAIN CONTAINERS, INC.20070000.00800047 FLETCHER OIL & REF CO 2000 42,094 0 42,094 0.06800184 GOLDEN WEST REF CO 2001 150,557 243 150,314 0.21800232 HUNT-WESSON INC 1996 9,564 0 9,564 0.01Total from shutdown facilities (tons per day) 1.42From Glass Facilities (tpd) 0.85Final Staff Report – Part I Appendix A – 2005 SOx RECLAIM Emissions____________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 244 November 2, 2010TABLE A-42005 SOx Emissions of Top Seven Groups of EquipmentGroupFac Name Description Fuel Type 2005 Emissions (lbs) 2005 Emissions (tpd)1B REGENERATOR, FCCU755399.17 1.031F REGENERATOR, FCCU447175.34 0.611A REGENERATOR281211.84 0.391D REGENERATOR195964.32 0.271D BOILER30445.34 0.041C REGENERATOR703085.36 0.961E REGENERATOR, FCCU0 0.001E BOILER, CO WASTE HEAT, FCCU181757.45 0.25Total for 6 FCCUs3.552B HEATER, CRUDE OIL DISTILLATION REF_GAS57649.9 0.082D BOILER REF_GAS25516.55 0.032D HEATER REF_GAS47760.79 0.072D FURNACE REF_GAS32123.51 0.042C HEATER REF_GAS76489.74 0.102C HEATER REF_GAS64590.83 0.092C BOILER REF_GAS45844.81 0.062C BOILER REF_GAS43162.12 0.062C HEATER REF_GAS30440.13 0.042C HEATER REF_GAS28672.09 0.042C HEATER REF_GAS27970.11 0.042E HEATER, COKING PROCESS PROCESS GAS, REF GAS48332.59 0.072E HEATER, CRUDE UNIT PROCESS GAS, REF GAS39770.77 0.052E HEATER, COKING PROCESS PROCESS GAS, REF GAS39577.84 0.052E BOILER, HYDROGEN GENERATION REF GAS, NAT GAS28868.34 0.042E BOILER, STEAM GENERATIONREF GAS, PROCESS GAS FROMSCRUBBER26484.59 0.04Total for 16 boilers/heaters (1 currently not in operation)0.913EEINCINERATOR (C54), CONTROL EQUIP FORABSORBER OF SULFUR RECOVERY UNITREF GAS, NAT GAS, PROCESSGAS32995.62 0.053EEINCINERATOR (C56), CONTROL EQUIP FORABSORBER OF SULFUR RECOVERY UNITREF GAS, NAT GAS, PROCESSGAS11974.31 0.023B CONTROL DEVICE (C-910) THERMAL OXIDIZERREFINERY GAS, NATURAL GAS,WASTE GAS114337.58 0.163B CONTROL DEVICE, THERMAL OXIDIZERREFINERY GAS, NATURAL GAS,WASTE GAS111676.16 0.153F OXIDIZER116994.68 0.163ATHERMAL OXIDIZER (D927), TAIL GAS IN SULFURPRODUCTION UNIT NATGAS, REF GAS75220.2 0.103ATHERMAL OXIDIZER (D927), TAIL GAS IN SULFURPRODUCTION UNIT NATGAS, REF GAS62774.65 0.09Final Staff Report – Part I Appendix A – 2005 SOx RECLAIM Emissions____________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 245 November 2, 2010TABLE A-4 (Continued)GroupFac Name Description Fuel Type 2005 Emissions (lbs) 2005 Emissions (tpd)3ATHERMAL OXIDIZER (D911), TAIL GAS IN SULFURPRODUCTION UNIT NATGAS, REF GAS47309.99 0.063D OXIDIZER112186.65 0.153CINCINERATOR (C456), SULFUR RECOVERY UNITNO 2, TAIL GAS INCINERATOR REF GAS, NAT GAS7518.47 0.013CINCINERATOR (C436), SULFUR RECOVERY UNITNO 1, TAIL GAS INCINERATOR REF GAS, NAT GAS7005.95 0.01Total for 11 SRU/Tail Gas Units0.964B FURNACE, SULFURIC ACID PLANT FUELOIL, NAT_GAS, SULFUR821456.88 1.134AREACTOR, SULFURIC ACID PRODUCTION,COMBUSTION CHAMBER PROCESS GAS28304 0.044AREACTOR, SULFURIC ACID PRODUCTION,COMBUSTION CHAMBER REFGAS, NATGAS443.05 0.00Total for 3 Sulfuric Acid Manufacturing Reactors/Furnace1.165BG FURNACE NAT_GAS55242.68 0.085BG FURNACE, MELTING NAT_GAS, OXY-FUEL, PROPANE, GLASS61637.19 0.085BG FURNACE, MELTING NAT_GAS, OXY-FUEL, PROPANE, GLASS26411.28 0.045SG FURNACE, MELTING FUEL OIL, NAT_GAS, OXY FUEL, GLASS93706.37 0.13Total for 4 Container Glass Melting Furnaces0.326BW KILN, ROTARY, CALCINER PET COKE NATURAL GAS, DIESEL FUE:257392.34 0.35Total for 1 coke calciner0.357CC KILN COAL, COKE, FUEL OIL, NAT GAS, TIRE140815.54 0.197CC KILN COAL, COKE, FUEL OIL, NAT GAS, TIRE54045.06 0.072CCBOILER, STEAM GENERATION, CIRCULATINGFLUIIZED BED COAL, COKE, NAT GAS1561.82 0.00Total for 2 cement kilns0.27TOTAL 7 CATEGORIES OF EQUIPMENT7.53Final Staff Report – Part I Appendix B – Summary of Federal, State and Local SOx Requirements____________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 246 November 2, 2010Appendix B – Summary of Federal, State and Local SOx Rule Requirements(Summarized by Kevin Orellana)Fluid Catalytic Cracking UnitsRule/Regulation Applicability Emission Limits ComplianceDateMonitoring**SCAQMD R1105 FCCU 132 lbs SO2per 1000 bbl feed (60-minute average) 1/1/1987BAAQMD 9-1 FCCU 1000 ppmv SO23/15/1995 CEMSSan Diego County APCDR53Other sources of gaseous sulfur emissionswhere sulfur compounds emitted are notproducts of fuel combustion0.05 % by volume dry, sulfur as SO21/22/1997NSPS 40 CFR Part 60Subpart JaFCCU 25 ppmv SO2dry basis, 365-day rolling average 5/14/2007 CEMSSulfur Recovery Units/Tail Gas UnitsRule/Regulation Applicability Emission Limits ComplianceDateMonitoring**SCAQMD R468 SRU 500 ppm sulfur compounds (calculated as SO2dry)over 15 minute average; and 10ppm H2S over 15-minutes (dry); and 198.5 lbs./hr sulfur compoundsas SO210/8/1976BAAQMD 9-1 SRU 250 ppmv SO2dry @ 0% O23/15/1995 CEMSSan Diego County APCDR53Sulfur recovery plants 0.05% by volume dry, sulfur as SO21/22/1997NSPS 40 CFR Part 60Subpart JaSRU with capacity >20 long tons/day,followed by incineration250 ppmv SO2dry @ 0% O25/14/2007 CEMSNSPS 40 CFR Part 60Subpart JaSRU with capacity >20 long tons/day,followed by incineration, with multipletrains or release points250 ppmv SO2dry @ 0% O2for each process trainor release point; or comply with a flow-weightedaverage of 250 ppmv for all release points5/14/2007 CEMSNSPS 40 CFR Part 60Subpart JaSRU with capacity >20 long tons/day, notfollowed by incineration10 ppmv H2S and 300 ppmv of reduced sulfurcompounds (H2S, COS, and CS2), each calculatedas ppmv of SO2dry @ 0% O25/14/2007 CEMSFinal Staff Report – Part I Appendix B – Summary of Federal, State and Local SOx Requirements____________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 247 November 2, 2010Refinery Boilers/HeatersRule/Regulation Applicability Emission Limits ComplianceDateMonitoring**NSPS 40 CFR Part 60Subpart JaFuel gas combustiondevices162 ppmv H2S in fuel gas determined hourly on a 3-hour rollingaverage basis or 60 ppmv in fuel gas determined daily on a 365successive calendar day rolling average basis5/14/2007 CFGMSNSPS 40 CFR Part 60Subpart JaFuel gas combustiondevices20 ppmv flue gas SO2(dry @ 0% O2) determined hourly on a 3-hourrolling average basis, and 8 ppmv flue gas SO2 (dry @0% O2)determined daily on a 365 successive calendar day rolling averagebasis5/14/2007 CEMSSCAQMD R431.1 Fuel gas combustiondevices40 ppmv averaged over 4 hours, calculated as H2S 5/4/1994 CFGMS orCEMSSJVUAPCD R4301 Fuel burning equipment 200 lb/hr sulfur compounds, calculated as SO212/17/1992Coke CalcinersRule/Regulation Applicability Emission Limits ComplianceDateMonitoring**SCAQMD R1119 Coke Calcining At least 80% reduction of uncontrolled SOxemissions7/1/1983BAAQMD 9-1 Coke Calcining kilns 400 ppmv or 250 lb/hr SO23/15/1995San Diego County APCDR53Other sources of gaseous sulfur emissions wheresulfur compounds emitted are not products offuel combustion0.05 % by volume dry, sulfur as SO21/22/1997Sulfuric Acid PlantsRule/Regulation Applicability Emission Limits ComplianceDateMonitoring**SCAQMD R469 Sulfuric Acid 500 ppm sulfur compounds (calculated asSO2dry) over 15 minute average; 198.5lbs./hr sulfur compounds as SO22/13/1981BAAQMD 9-1 Sulfuric acid plant equipment 300 ppmv SO2@12% O23/15/1995 CEMSSan Diego County APCDR53Other sources of gaseous sulfur emissions wheresulfur compounds emitted are not products offuel combustion0.05 % by volume dry, sulfur as SO21/22/1997NSPS 40 CFR Part 60Subpart HSulfuric Acid production units 4 lb SO2per ton of acid produced (as 100%H2SO4)6/14/1974 CEMSFinal Staff Report – Part I Appendix B – Summary of Federal, State and Local SOx Requirements____________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 248 November 2, 2010Cement KilnsRule/Regulation Applicability Emission Limits ComplianceDateMonitoring**San Diego County APCDR53Other sources of gaseous sulfur emissions where sulfurcompounds emitted are not products of fuel combustion0.05 % by volume dry, sulfur asSO21/22/1997SJVUAPCD R4801 Any equipment that discharges gaseous sulfur compounds 0.2% by volume SO2dry, over15 min-average12/17/1992Glass ManufacturingRule/Regulation Applicability Emission Limits ComplianceDateMonitoring**San Diego County APCDR53Other sources of gaseous sulfur emissions where sulfurcompounds emitted are not products of fuel combustion0.05 % by volume dry, sulfur asSO21/22/1997SJVUAPCD R4354 Glass melting furnaces 0.90 lb SOx per ton glassproduced (rolling 30-dayaverage)1/1/2011 CEMSInformation related to the U.S. EPA Consent Decree for FCCUs are summarized below:Emission Limits Compliance Date MonitoringBP:50 ppmv SO2@ 0% O2, 365-day rolling average;150 ppmv SO2@ 0% O2, 7-day rolling average7/11/2005 CEMSTesoro:36.2 ppmv SO2@ 0% O2, 365-day rolling average;69.1 ppmv SO2@ 0% O2, 7-day rolling average2/2/2006 CEMSValero:No set limit at this time due to anongoing demonstration project with SO2reducing catalystsdue by the compliance date.4/30/2011 CEMSExxonMobil:25 ppmv SO2@ 0% O2, 365-day rolling average;50 ppmv SO2@ 0% O2, 7-day rolling average12/13/2005 CEMSChevron:25 ppmv SO2@ 0% O2, 365-day rolling average;50 ppmv SO2@ 0% O2, 7-day rolling average12/31/2005 CEMSConocoPhillips:25 ppmv SO2@ 0% O2, 365-day rolling average;50 ppmv SO2@ 0% O2, 7-day rolling average3/1/2011 CEMSFinal Staff Report – Part I Appendix C – CEMS & Source Test Data____________________________________________________________________________________________________________________________________Proposed Amended Regulation XX Part I - 249 November 2, 2010Appendix C – CEMS Information & Source Test DataTable C-1: CEMS Data from a Refinery inthe District – FCCU with Wet Gas ScrubberSOxEm issionsSOxEm issionsSOxEm issionsSOxEm issionsSOxEm issionsSOxEm issionsSOxEm issionslbs/day Day lbs/day Day lbs/day Day lbs/day Day lbs/day Day lbs/day Day lbs/day Day111.09 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 3/31/09 149.71 5/11/09111.02 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 4/1/09 149.85 5/12/09110.09 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 4/2/09 149.85 5/13/09109.51 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 4/3/09 149.82 5/14/09110.36 9/17/08 143.55 10/25/08 123.43 12/4/08 157.15 1/14/09 149.61 2/23/09 4/5/09 149.47 5/15/09119.47 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 4/6/09 149.11 5/16/09129.49 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 4/7/09 149.16 5/17/09130.41 9/20/08 143.3 10/28/08 123.13 12/7/08 158 1/17/09 153.88 2/26/09 174.53 4/8/09 149 5/18/09130.88 9/21/08 143.92 10/29/08 125 12/8/08 149.89 1/18/09 156.03 2/27/09 152.39 4/9/09 5/19/09130.75 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 4/10/09 150.05 5/20/09130.93 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 4/11/09 150.46 5/21/09131.86 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 4/12/09 150.32 5/22/09130.62 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 4/13/09 149.93 5/23/09130.69 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 4/14/09 149.89 5/24/09125.6 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 4/15/09 150.07 5/25/09132.65 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 4/16/09 149.87 5/26/09131.76 9/29/08 130.27 11/6/08 134.89 12/17/08 158.07 1/26/09 143 3/7/09 148.51 4/17/09 149.28 5/27/09128.53 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 4/18/09 149.69 5/28/09127.41 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 4/19/09 149.55 5/29/09129.48 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 4/20/09 149.49 5/30/09131.67 10/3/08 138.12 11/10/08 138 12/21/08 153.98 1/30/09 111.54 3/11/09 147.47 4/21/09 148.77 5/31/09132.49 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 4/22/09 147.92 6/1/09131.92 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 4/23/09 148.77 6/2/09131.33 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 4/24/09 148.87 6/3/09131.02 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 4/25/09 148.31 6/4/09119.64 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 4/26/09 148.7 6/5/09154.21 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 4/27/09 149.28 6/6/09154.71 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 4/28/09155.74 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 4/29/09156.58 10/12/08 137.07 11/19/08 155.95 12/30/08 159.41 2/8/09 119 3/20/09 138.9 4/30/09146.18 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 5/1/09128.23 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 5/2/09132.85 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 5/3/09140.19 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 5/4/09139.43 10/17/08 134.1 11/24/08 144 1/4/09 148.28 2/13/09 136.13 3/25/09 148.97 5/5/09140.03 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 5/6/09140.16 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 5/7/09143.02 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 5/8/09122.14 11/28/08 154.11 1/8/09 149.17 2/17/09 138.11 3/29/09 149.51 5/9/09122.55 11/29/08 156.96 1/9/09 145.34 2/18/09 136.85 3/30/09 149.32 5/10/09The concentration during 265 days (8.83 months) is 3.80 ppmv, however this refinery reported emissions based on a level of 5ppmv.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 A verage 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

A

verage 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/Cir culation 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 NO 2 – Method 100.1 LIMIT(S) as found ppmv 12.1 18.4 17.8 16.08

at 3% O 2 ppmv 11.0 16.8 16.2 14.7

at 0% O 2 % 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% O 2 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- A

verage ppmv 58.46

at 3% O 2 ppmv 53.39
emission rate lbs/hr 19.07

Sulfur Oxides as SO 2 – 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% O 2 ppmv 1.160 0.739 0.644 0.848 SOx Conc. in Gas Sample at 0% O 2 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
103 Isokinetic Sampling Rate (I) % 103 104 102 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% O 2 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% O 2 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 1.00Final 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 th e 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 9 90<=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% O 2 gr/dscf 0.08770 0.09996 0.15006 0.11257
Inlet PM emission rate lb/hr 84.47 101.49 163.82 116.59Final 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 in formation 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 distri bution 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 fac ility 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 fac ility 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 processe s at your facility? If yes, wh o 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 provi de us a copy of your facility’s wastewater discharge permits.

Solid Waste

1. How does the refinery currently handle th e catalyst fines from the ESPs? Where ar e 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 f acility 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 fr om regenerator (millions dry standard cubic feet) and exhaust temperatures (degree Fahrenheit)

⎯ Average and range of SOx concentration in the exha ust flue gas from the FCCU regenerator (ppmv at %O 2 )

b) Does the facility currently use FCCU SOx reduction catal ysts? 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 ava ilable, please submit a copy of manufacturer's quote including specifications and guarantee

⎯ Costs of SOx reduction catalysts. Please provide annua l 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 absorben t, 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 av erage (millions dry standard cubic feet)

⎯ Annual average and range of the SOx concentrati ons in the exhaust flue gas (ppmv at 3%O2)

b) Does the facility currently use any SOx control technol ogy 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, ab sorbent 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 ope rational 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 me thod used to determine the sulfur removal efficiency

⎯ Flue gas exhaust flow rate, range and av erage (millions dry standard cubic feet)

⎯ Annual average and range of the SOx con centrations 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 conve rter, 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 av erage, (millions dry standard cubic feet)

⎯ Range and average of SOx concentrati ons in the exhaust flue gas (ppmv)

⎯ Annual average SOx emission rate (l bs 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, ab sorbent 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 material s (e.g. limestone, soda ash, cullet)

⎯ Flue gas exhaust flow rate, range and av erage (millions dry standard cubic feet)

⎯ Annual average and range of SOx concentra tions 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, ab sorbent 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 % O 2 ) and annual average

⎯ Annual average SOx emission rate (l bs 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, absorb ent 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 % O 2 ) and annual average

b) Does the facility currently use any SO x 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, absorb ent 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 operati ng costs, cost effectiveness analysis, manufacturer's specifications, and guarantee

⎯ If available, the facility’s name that cu rrently 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.govFinal 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, th e refineries installed control equipment to

meet the PM10 and ammonia emission standards of Ru le 1105.1. Four refineries selected to install dry electrostatic precipitators (ESPs ) and one refinery installed a co mbination of a wet gas scrubber and a wet electrostatic precipitator (WGS/W ESP). A summary of the control equipment manufacturers, contractors, constr uction 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 110 5.1 in 2003, Refinery K indicated th at they did not have enough space to install dry ESPs but planne d to install a WGS to comply with the proposed rule. Refinery K developed a cost estimate for the project incl uding a BELCO WGS, a pur ge treatment unit, and induced draft fan to overcome pressu re drop, a gas-to-gas heat exchan ger 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, re viewed the costs estimated by Refinery K, and added additional costs for demolition, modification of the SRU/TGs, elec trical substation, and wastewater treatment, tie-in costs for NOx contro l, paving, and opportunity lost costs for extended turnaround. The result was an estimate of $78.7 million dollars capital cost s as shown in Table 1. 93

In 2007-2008, Refinery K decided to install ESPs, a nd 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 repo rted 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 Th e 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

36.8 3 times higher (36.8/10.7 = 3.4) Electrical Substation 0.8 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, Refine ry Y indicated that th ey would install a dry ESP to comply with the proposed rule. Refine ry Y developed a cost estimate for the project including a Hamon Research Cottrell’ s ESP. There were also extens ive 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 fo r additional ducting and supports, insulation, asbestos abatement, SCR/stack re location, new foundations and paving, electrical instrumentation and controls, pipi ng relocation, and demolition. Th e estimated capital costs were $48.9 million. 95 In 2007-2008, Refinery Y installed ESPs. Re finery 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 a nd the cost estimates are shown in Table 2. The reported equipment costs are 35% hi gher than the estimated costs. The site preparation costs are

almost the same as estimated. There are substantia l differences in the installation costs including ducting, supports, electrical subs tation modification, and engineer ing/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 milli on), 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 approx imately $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; Miscella neous = $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 millio n. In a recent e-mail comm unication 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. Refine ry W and WSPA’s consultant developed a cost estimate for the project including a large ESP a nd extensive costs for duc ting, relocation of a roadway, underground sewers and drains, piling, dis posal of contaminated soil, new electrical substation, SCR, engineering/management, and ex tended shutdown. The estimat ed 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 substa tion modification etc., which cause the reported installation costs to rise up to 9 times higher than estimated, a nd the overall reported co sts 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 9.1 102 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 Contro l of PM-10 Emissions at South Coast Refinery FCCUs (SCAQMD Proposed Rule 1105.1), NEXANT, Inc. for Th e Western States Petroleu m Association, May 2003. NEXANT estimated ESP costs from $8 - $12 million. Site pr eparation costs included relocating a refinery road ($400,000), relocating sewers/drains/piping ($650,000), dispos al 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 decide d 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 th e 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 in stallation costs including construction, demolition, and engineering and the reported owner’s cost s are approximately 6 times higher than 2003 estimates. The overall 2010 reported costs are appr oximately 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 in dicated that they would install ESPs to meet the requirements of Rule 1105.1. Re finery L hired a consultant (Jaco bs Engineering) to develop a feasibility and cost estimate to comply with th e proposed Rule 1105.1 limit for both ESPs and WGS. Jacobs Engineering recommended Refi nery 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 We stern States Petroleum Association, May 2003. The costs were estimated for two new ESPs in paralle l, 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 co sts. 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 cost s of $102 million dollars reported as the actual costs for this project provided by Re finery L are presented in Table 6. 106

TABLE 6 Cost Estimates and Reported Capital Costs (Million Dollars)

Cost Estimates Repo rted Costs Difference Equipment Cost 10 17.547 2 times higher (17.5/10 = 1.8) Project Management 10.66 6.23 2 times higher (15.5/10.66 = 1.5) Engineering 9.27

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, installati on costs, and capital costs are c onsistently 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 differen t than estimated. The reported costs are about 35% higher for Refinery Y and Refinery X, 2 time s higher for Refinery W and L, and 10% lower for Refinery K. The differences are due to infla tion (about 3% between 2003 and 2010), extra capacity for redundancy built in the design, and the pr ice 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 We stern 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 co mbined 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 m illion 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 milli on), 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 e quipment 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 installa tion 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. Th e vast differences origin ate 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 build ings, b) insulation for ducting/ piping, c) substantial amount for wiring/conduit for substation and power di stribution, and d) s ubstantial amount for instrument/controls. These categories are underes timated in 2003, especially the costs for steel, electrical wiring, and instrument/controls. Co sts 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, a nd during 2008, there was a period of hyper inflation in heavy industrial constr uction equipment and labor costs.

⎯ Union Labor Costs. Due to the volume of construction ac tivity 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 not e 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 cons truction 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 substant ially 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 th e ESP, larger than estimated in 2003.

Capital Costs

Overall, the reported capital costs are higher than es timated: 2 times higher for Refinery K, X and L, 4 times higher for Refinery W, and 7 times higher fo r 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 av erage 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 Re finery 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 re ported in 2003) is about the same as Refinery K’s (212,514 acfm total gas flow) however the re ported 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 extraordin ary 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 Ac tual 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 Refine ry K, Y, and L, and 8 times higher for Refinery W. It is interesting to note that there are two dis tinct 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, electri cal substation modification, NOx/S Ox CEMS) and used more in engineering and management compar ed 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 BARC T 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 Info rmation Administration)

RANK CORPORATION COMPANY STATE SITE Barrels per Calendar Day

1 EXXON MOBIL CORP EXXONMOBIL REFINI NG & 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 MARA THON 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 REFINI NG & 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 PARTNE RSHIP Texas DEER PARK 327,000

12 KOCH INDUSTRIES INC Flint Hills Res ources 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 COMP ANY 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 CO MPANY Louisiana WESTLAKE 239,400

23 EXXON MOBIL CORP EXXONMOBIL REFINI NG & SUPPLY CO Illinois JOLIET 238,600

24 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY N ew Jersey LINDEN 238,000

25 MOTIVA ENTERPRISES LLC Motiva Ente rprises LLC Louisiana CONVENT 235,000

26 MOTIVA ENTERPRISES LLC Motiva Enterprises LLC Louisiana N ORCO 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 N ORTH POLE 219,500

30 VALERO ENERGY CORP VALERO REFINING CO TEXAS LP Texas TEXAS CITY 214,000

31 MARATHON OIL CORP MARA THON PETROLEUM CO LLC Kentucky CATLETTSBURG 212,000

32 MARATHON OIL CORP MA RATHON 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 N ORCO 185,003Final Staff Report – Part 1 Appendix F – U.S. Refineries Operable Capacities

_________________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 268 November 2, 2010 36 CONOCOPHILLIPS CONOCOPHILLIPS CO MPANY Pennsylvania TRAINER 185,000

37 VALERO ENERGY CORP PREMCOR REFINI NG 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 & MARK ETING CO California MARTINEZ 166,000

42 PDV AMERICA INC CITGO REFINING & CH EMICAL INC Texas CORPUS CHRISTI 163,000

43 SUNOCO INC SUNOCO INC Ohio TOLEDO 160,000

44 VALERO ENERGY CORP VALERO REFINING CO NEW JERSEY N ew Jersey PAULSBORO 160,000

45 ROYAL DUTCH/SHELL GROUP Shell Oil Products US California MARTINEZ 156,400

46 HUSKY ENERGY INC LIMA REFI NING 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 CO MPANY 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 REFI NING COMPANY LP Texas EL PASO 122,000

56 CONOCOPHILLIPS CONOCOPHILLIPS COMPANY California RODEO 120,200

57 MURPHY OIL CORP MURPHY OI L USA INC Louisiana MERAUX 120,000

58 TESORO CORP Tesoro West Coast Washington ANACORTES 120,000

59 CVR ENERGY INC COFFEYVILLE RESOURCES RF G & MKTG LLC Kansas COFFEYVILLE 115,700

60 MARATHON OIL CORP MA RATHON PETROLEUM CO LLC Michigan DETROIT 106,000

61 HOLLY CORP N AVAJO REFINING CO N ew Mexico ARTESIA 105,000

62 CONOCOPHILLIPS CONOCOPHILLIPS CO MPANY Washington FERNDALE 100,000

63 PETROLEO BRASILEIRO SA PASADENA REFI NING 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 N CRA 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 N ew 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 78,000Final 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 MA RATHON PETROLEUM CO LLC Texas TEXAS CITY 76,000

78 ERGON INC LION OIL CO Arkansas EL DORADO 75,000

79 MARATHON OIL CORP MARATHON PETROL EUM CO LLC Minnesota SAINT PAUL 74,000

80 SINCLAIR OIL CORP SINCLAIR WYOMIN G 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 REFINI NG & 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 N orth 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 CORPORAT ION California PARAMOUNT 53,000

101 FRONTIER OIL REFINING &

MKTG FRONTIER REFINING INC Wyoming CHEYENNE 47,000

102 CHEVRON CORP CHEV RON 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 N USTAR ENERGY LP N USTAR ASPHALT REFINING LLC N ew 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 N ORTH SALT

LAKE 29,400

110 N USTAR ENERGY LP N USTAR 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 24,500Final 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 N ew Mexico GALLUP 20,800

117 ERGON INC ERGON WEST VIRGINIA INC West Virginia N EWELL 20,000

118 ARCTIC SLOPE REGIONAL CORP PETRO STAR INC Alaska N ORTH POLE 19,700

119 WESTERN REFINING INC. WESTERN REFINING SOUTHWEST INC N ew 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 N EW 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 Ut ah 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 N evada ELY 2,000

*Only Refineries with Atmospheric Crude Oil Distillation Capacity.

Source: Refinery Capacity Data by individual refinery as of January 1, 2010Final 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 Informati on Administration “Capacity of Oper able Petroleum Refineries by State as of January 1, 2010”



### CORPORATION COMPANY_NAME SITE PRODUCT QUANTITY (Barrels Per

Calendar Da y) 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 31,958Final 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 magazi ne, dated July 26, 2010. As explained in the Fortune magazine, Fortune Global 500 ranks 500 corpor ations 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 Gl obal 500 must publish financial data and report pa rt 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 orig inally reported for that year. The list shows that general global economy is down for almost all cor porations 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 & Complia nce team on February 23, 2010 as the base. The AQMD’s AER team refined and distributed the audi ted 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 th e 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 cont rols 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 fr om R431.1 & 431.2 when appropriate. The seven new

rules with 2019 contro l 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 remaini ng SOx emissions are ca lculated to reflect

controls from all rules. The 2019 SOx baselin e 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 5.12Final Staff Report – Part 1 Appendix I – Projected 2019 Emissions & Growth Factors

_________________________________________________________________________________________________ Proposed Amended Regulation XX Part I - 274 November 2, 2010 The above resulting table with more details is se nt to the Rule Staff fo r further analysis.

Composite Growth Factors (2005-2019)

Rule Staff requested 2005-2019 composite growth factors for R469 (Sulfuri c 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 proj ected emissions are then grou ped by rule by facility. To calculate the composite growth f actors 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 An alysis is a stand-alone document attached by reference.)



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