# CHASE

POWER DEVElOPMENT.llC



### October 28, 2011

Mr

. Jeff Robinson Chief, Air Permits Section U

. S

. EPA Region 6, 6PD 1445 Ross Avenue, Suite 1200 Dallas, TX 75202-2733 110 1 1 Richmond,Suite3S0 t. 7 1 3-35 1 -6700 Houston T exas 77042 ( 7 1 3·351 · 6750



### RE: Application for a Prevention of Significant Deterioration Air Quality Permit for Greenhouse Gas Emissions Las Brisas Energy Center, LLC Corpus Christi, Nueces County, Texas
Dear Mr. Robinson:
Chase Power Development LLC., on behalf of Las Brisas Energy Center, LLC (LBEC) is hereby submitting this application for a Prevention of Significant Deterioration (PSD) air quality permit for greenhouse gas emissions for the construction of a new circulating fluidized bed steam electric generation facility on the Joe Fulton Corridor bordering the west side of the Port of Corpus Christi Bulk Terminal in Corpus Christi, Texas

. The Plant is authorized for emissions of all non-greenhouse gas air contaminants under Texas Commission on Environmental Quality (TCEQ) Permit No

. 85013/PSD-TX1138/HAP-48. General information for the application is provided on the TCEQ Form PI-1

- General Application for Air Preconstruction Permit and Amendments. The U.S. Environmental Protection Agency's (EPA) document entitled "PSD and Title V Permitting Guidance For Greenhouse Gases " , dated November 2010 and March 2011 , was utilized as a guide for preparation of the attached application

. LBEC is committed to working closely with EPA Region 6 to get the application review completed as expeditiously as possible. LBEC will be contacting your staff soon after submittal of this application to arrange a meeting to review the application and answer any questions that your team may have after initially reading our application

.

### October 28, 2011 Mr. Jeff Robinson Page 2

Should you have any questions regarding this application , please contact me either by e - mail at j ohnupc hur ch@c h ase - powe r. co m or by telephone at (713) 351-6701

.

# S;"?7~ 

# iip'h""h**~-~ ,** 

Managing Partner 

### Chase Power Deve l opment L L C.

Enclosure

cc: Mr. Mike Wilson, P.E., Director, Air Permits Division, TC E Q

Mr. Larry Moon, P.E., Zephyr Environmental Corporation

### PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT ApPLICATION FOR A NEW CIRCULATING FLUIDIZED BED STEAM ELECTRIC GENERATING FACILITY LAS BRISAS ENERGY CENTER, LLC CORPUS CHRISTI, NUECES COUNTY, TEXAS

SUBMI7TED TO: 

### ENVIRONMENTAL PROTECTION AGENCY REGION VI MULTIMEDIA PLANNING AND PERMITTING DIVISION FOUNTAIN PLACE 12TH FLOOR, SUITE 1200 1445 Ross AVENUE DALLAS, TEXAS 75202-2733

SUBMI7TED BY: 

### LAS BRISAS ENERGY CENTER, LLC

CORPUS CHRISTI, TEXAS 78409

PREPARED BY: 

### ZEPHYR ENVIRONMENTAL CORPORATION 2600 VIA FORTUNA, SUITE 450 AUSTIN, TEXAS 78746

OCTOBER, 2011P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 i 

### TABLE OF CONTENTS

1.0 INTRODUCTION

................................ ................................ ................................ ............. 1 FORM PI

- 1 GENERAL APPLICATIO N

................................ ................................ ....................... 4 2.0 PROJECT SCOPE

................................ ................................ ................................ ........ 14 2.1 Plant Design Considerations

................................ ................................ ................ 14 2.2 CFB Boilers

................................ ................................ ................................ ......... 17 2.3 Auxiliary Bo ilers

................................ ................................ ................................ ... 17 2.4 Propane Vaporizers

................................ ................................ ............................. 18 2.5 Diesel

- Fired Emergency Equipment

................................ ................................ ..... 18 2.6 Electrical Equipment Insulated with Sulfur Hexafluoride (SF 6 )

.............................. 18 PROCESS FLOW DIAGRAM

................................ ................................ ................................ .... 19 PLOT PLAN

................................ ................................ ................................ .............................. 20 AREA MAP

................................ ................................ ................................ ............................... 21 3.0 GHG EMISSION CALCULA TIONS

................................ ................................ ................ 22 3.1 GHG Emissions From CFB Boilers

................................ ................................ ...... 22 3.2 GHG Emissions From Auxiliary Boilers

................................ ................................ 23 3.3 GHG Emissions From Propane Vaporizers

................................ .......................... 23 3.4 GHG Emissions From Natural Gas Piping Fugitives

................................ ............ 24 3.5 GHG Emissions From Diesel Fired Emergency Engines

................................ ...... 24 3.6 GHG Emissions From Electrical Equi pment Insulated with SF 6 ............................ 24 4.0 PREVENTION OF SIGNIF ICANT DETERIORATION APPLICABILITY

......................... 33 TCEQ PSD NETTING TAB LES

................................ ................................ ................................ 34 5.0 BEST AVAILABLE CONTROL TE CHNOLOGY (BACT)

................................ ................ 38 5.1 Definition of BACT

................................ ................................ ............................... 38 5.2 BACT for the CFB Boilers

................................ ................................ .................... 39 5.2. 1 Step 1: Identify All Available Control Technologies 39 5.2.2 Step 2: Eliminate Technically Infeasible Options 45 5.2.3 Step 3: Rank Remaining Control Technologies 48 5.2.4 Step 4: Evaluate Most Effective Controls and Document Results 48 5.2.5 Step 5: Select BACT 48 5.3 BACT for SF 6 Insulated Electrical Equipment

................................ ....................... 49 5.3.1 Step 1: Identify All Available Control Technologies 49 5.3.2 Step 2: Eliminate Technically Infeasible Options 50 5.3.3 Step 3: Rank Remaining Control Technologies 50 5.3.4 Step 4: Evaluate Most Effective Controls and Document Results 50 5.3.5 Step 5: Select BACT 50 5.4 BACT for Auxiliary Boilers and Propane Vaporizers

................................ ............. 51 5.5 BACT for Emergency Engines

................................ ................................ ............. 52 MAP OF EXISTING CO 2 PIPELINES AND POTENT IAL GEOLOGIC STORAGE SITES IN TEXAS

................................ ................................ ................................ .......................... 53P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 ii TABLE 5

- 1

................................ ................................ ................................ ................................ 55 6.0 OTHER PSD REQUIREMEN TS

................................ ................................ .................... 56 6.1 Impacts Analysis

................................ ................................ ................................ .. 56 6.2 GHG Preconstruction Monitoring

................................ ................................ ......... 56 6.3 Additional Impacts Analysis

................................ ................................ ................. 56 7.0 GHG MONITORING

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



### APPENDICES

APPENDIX A COPY OF PERMITS 85013, HAP48, AND PSDTX1138

APPENDIX B GHG PSD APPLICABILITY FLOWCHART

– NEW SOURCESP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 1 

## 1.0 I NTRODUCTION
Las Brisas Energy Center, LLC (Las Brisas) proposes to construct and operate a new circulating fluidized bed (CFB) steam electric generation facility , known as the Las Brisas Energy Center (LBEC), on the Joe Fulton Corridor bordering the west side of the Port of Corpus Christi Bulk Terminal in Cor pus Christi, Texas. The facility, with a n approximate nominal capacity of generating 1,200 megawatts electricity (MWe), will provide electricity to the existing regional grid.

More than three years ago, Las Brisas began the Prevention of Significant De terioration (PSD) air permitting process in its effort to build the LBEC to be fueled by petroleum coke , a fuel that is produced in significant quantity in the nearby Corpus Christi refineries and, generally, in the Gulf Coast region

. Las Brisas submitted an air permit application to the Texas Commission on Environmental Quality ( TCEQ ) on May 19, 2008, which the TCEQ Executive Director ( ED ) declared administratively complete on May 23, 2008. Thereafter, the ED commenced technical review of the application and, on January 7, 2009, after completing that review, made the preliminary decision to issue the permit. Having preliminarily decided to issue the permit, the ED also issued a draft permit for public notice and comment at that time. On June 11, 2009, f ollowing the close of the public comment period, the ED issued his response to public comments along with a revised draft permit. In addition to affording the public the opportunity to provide comments regarding the permit application and draft permit, the TCEQ permitting process also affords interested parties the opportunity to participate in a trial

- like contested case hearing pro cess before the State Offi ce of Administrative Hearings ( SOAH)

. Such a hearing , including a remand proceeding, 1 regarding the LBEC PSD air permit spanned the time from February 2009 to November 2010 and, on December 1, 2010, SOAH issued a revised Proposal For Decision . The TCEQ Commissioners considered the revised PFD on January 26, 2011, and voted to issue the LBEC PSD air permit. Motions for rehearing were overruled by operation of law on April 12, 2011, and , subsequently, Las Brisas received a signed permit dated April 18, 2011. The TCEQ permit does not a ddress greenhouse gas emissions but the LBEC is authorized for emissions of all non - greenhouse gas air contaminants under TCEQ Permit No. 85013/ PSD

- TX

- 1138/HAP

- 48 (copy provided in Appendix A)

. Acco rding to the U.S. Environmental Protection Agency (EPA) , PSD permits issued on or after January 2, 2011 must address greenhouse gas emissions unless the permitted source’s greenhouse gas emissions fall below the levels set forth in EPA’s Greenhouse Gas Tai loring Rule. See 75 Fed. Reg. 31,514, 31,523 (June 3, 2010). Because LBEC’s greenhouse gas emissions will not be below those levels, whether Las Brisas must obtain a separate greenhouse gas PSD permit for L BEC pursuant to the Tailoring Rule turns on whet her the PSD

1 The remand proceeding was delayed approximately six weeks due to a witness for a party opposing issuance of the permit being injured in an automobile accident.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 2 permit LBEC applied for almost three years ago and has received from TCEQ was “issued” prior to January 2, 2011. On April 2, 2010, almost two years after Las Brisas applied to TCEQ for the LBEC air permit, EPA explained that it saw no need to grandfather then

- pending permit applications from greenhouse gas requirements because such permit applications “should in most cases be issued prior to January 2, 2011.” 75 Fed. Reg. 17,004, 17,021 (Apr. 2, 2010). After finalizing its Tailoring Rule, EPA issued guidance explaining, among other things, PSD applicability under the rule. See EPA, PSD and Title V Permitting Guidance for Greenhouse Gases (Mar. 2011), available at http://www.epa.gov/nsr/ghgpermitting.html (last visited Apr. 24, 2011) (hereinafter “EPA’s Greenhouse Gas Permitting Guidance”). That guidance provides further insight into the basis of EPA’s expectation that the majority of PSD permits pending in April 2010 would be issued before January 2011, or within a period of just nine months. Specifically, EPA explains that “the date a permit is issued is not necessarily the same as the date the permit becomes effective or final agency a ction for purposes of judicial review” but instead is “when a permitting authority issues a PSD permit after public comment on a draft permit or preliminary determination to issue a PSD permit.” Id . at 3 n.6. EPA’s Greenhouse Gas Permitting Guidance furt her suggests that a “similar approach” to permit issuance should be used in states like Texas with “analogous administrative procedures.” Id. Applying a “similar approach” to the LBEC PSD permit, as EPA suggests, Las Brisas maintains that the LBEC PSD pe rmit was “issued” for purposes of EPA’s Tailoring Rule on June 11, 2009 when, after making the preliminary decision to issue the permit and receiving public comment, the ED issued his response to public comment and a revised draft permit. Nonetheless, EPA has indicated that Las Brisas must obtain a second PSD permit to authorize the LBEC greenhouse gas emissions because, in its view, the PSD permit Las Brisas received from TCEQ was issued after January 2, 2011.
Furthermore, o n December 13, 2010, EPA issue d a SIP Call, requesting the submission of revised State Implementation Plans (SIPs) from thirteen states, including Texas, as part of its new effort to regulate greenhouse gases. See 75 Fed. Reg. 77,698, 77,705 (Dec. 13, 2010). Texas was told that it ha d to submit a revised PSD SIP by December 1, 2011, or else EPA would issue its own PSD Federal Implementation Plan (FIP) at that time. Id . at 77,716; see also Clean Air Act § 110(c)(1)(A), 42 U.S.C. 7410(c)(1)(A) (describing EPA’s power to issue a FIP). Just over two weeks later, though, EPA, without prior notice, made an abrupt change in course, “correcting” its 1992 approval of Texas’s PSD SIP and issuing an interim final rule instantly imposing a FIP on Texas. See 75 Fed. Reg. 82,430 (Dec. 30, 2010) ( interim rule); see also 75 Fed. Reg. 82,365 (Dec. 30, 2010) (proposed rule).

Under the interim rule, EPA purportedly assumed the role of granting PSD permits for greenhouse gas

- emitting sources in Texas, including sources issued non

- greenhouse gas PSD per mits by TCEQ on or after January 2, 2011. 75 Fed. Reg. 82,365, 82,365. In taking this action, EPA did not provide notice and comment opportunity to the public , pointing to the “goodP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 3 cause” exception in the Administrative Procedure Act as a justification. 2 Id. at 82,434 (citing APA § 553(b)(3)(B)). EPA also said that it would seek notice and comment on a final rule to replace the interim one later in the year. Id. And on May 3, 2011, after the signed LBEC TCEQ PSD permit was received by Las Brisas, EPA issued the f inal r ule in apparent accordance with the APA strictures

— i.e. , without invoking an emergency “good cause” exception and after a period of notice and comment. See 76 Fed. Reg. 25,178, 25,179 (May 3, 2011).
At present, Las Brisas’ parent, C hase Power Development, LLC, is challenging both the interim and final rules in the United States Court of Appeals for the District of Columbia Circuit and that litigation will continue during the pendency of this permit application. D espite having a sign ed PSD permit, Las Brisas remains practically unable to build Las Brisas. Due to EPA’s December 30, 2010 issuance of the i nterim r ule partially disapproving Texas’s PSD SIP and imposing a FIP on Texas. I f Petitioner’s permit is considered issued after Ja nuary 2, 2011 , as EPA maint a ins , the permit w as issued under the fully approved Texas PSD SIP and, as a result, unquestionably constituted full authority for Petitioner to build Las Brisas. In other words, if not for the i nterim r ule, Texas would not have been divested of its authority to issue PSD permits, and Las Brisas would have clear authority to build L BEC without EPA issuing a supplemental greenhouse gas (GHG) PSD permit

. With today’s application and without waiving any arguments as to EPA’s lack of authority to require a supplemental GHG PSD permit , LBEC is applying to the EPA PSD approval of GHG emissions. Included in this application are a project scope description, GHG emissions calculations, GHG netting analysis, and a GHG Best Available Control Technology (BACT) analysis.

2 EPA claims that the use of the “good cause” exception was justified because “[u]nless and u ntil EPA promulgates this [interim final] rule, Texas sources will not have available a permitting authority to process their PSD permit applications and as a r esult, may face delays in construction and modification.” 75 Fed. Reg. at 82,434. However, EPA ’s presumption is incorrect because, if not for EPA’s own action partially disapproving the Texas PSD SIP, that SIP would have continued to serve as a valid and effective mechanism for TCEQ to continue processing PSD permit applications for sources in Texa s until at least the December 1, 2011 deadline for submitting a revised SIP. See United States v. Cinergy Corp. , 623 F.3d 455, 458 (7 th Cir. 2010) (Posner, J.).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 4 

## F ORM 

## PI-1 G ENERAL 

## A PPLICATIONTCEQ – 10252 (Revised 06/11) PI-1 Form Texas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

Important Note: The agency requires that a Core Data Form be submitted on all incoming applications unless a Regulated Entity and Customer Reference Number have been issued and no core data information has changed. For more information regarding the Core Data Form, call (512) 239-5175 or go to www.tceq.texas.gov/permitting/central_registry/guidance.html

. I. Applicant Information A. Company or Other Legal Name: Texas Secretary of State Charter/Registration Number ( if applicable ): B. Company Official Contact Name ( Mr. Mrs. Ms. Dr.): Title: Mailing Address: City: State: ZIP Code: Telephone No.: Fax No.: E-mail Address: C. Technical Contact Name ( Mr. Mrs. Ms. Dr.): Title: Company Name: Mailing Address: City: State: ZIP Code: Telephone No.: Fax No.: E-mail Address: D. Site Name: E. Area Name/Type of Facility: Permanent Portable F. Principal Company Product or Business: Principal Standard Industrial Classification Code (SIC): Principal North American Industry Classification System (NAICS): G. Projected Start of Construction Date: Projected Start of Operation Date: H. Facility and Site Location Inform ation (If no street address, provide clear driving directions to the site in writing.): Street Address:

City/Town: County: ZIP Code: Latitude (nearest second): Longitude (nearest second):

This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v16) Page _____ of _____ 

### 1 9 Las Brisas Energy Center, LLC

✔ John Upchurch Managing Partner 11011 Richmond Avenue, Suite 350
Houston TX 77042
713-351-6701 713-351-6751 johnupchurch@chase-power.com
✔ John Upchurch Managing Partner Las Brisas Energy Center, LLC 11011 Richmond Avenue, Suite 350
Houston TX 77042 713-351-6701 johnupchurch@chase-power.co m

Las Brisas Energy Center, LLC Las Brisas Energy Center, LLC ✔
Electric Power Generation
4939
221112
November 2012 January 2017

On the Joe Fulton Corridor bordering the west side of the Port of Corpus Christi Bulk Terminal
6509 Joe Fulton Corridor

Corpus Christi Nueces 78402
27° 49' 18" 97° 28' 38"TCEQ – 10252 (Revised 06/11) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v16) Page _____ of _____ Texas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

I. Applicant Information (continued) I. Account Identification Number (leave blank if new site or facility): J. Core Data Form. Is the Core Data Form (Form 10400) attached? If No , provide customer reference number and regulated entity number (complete K and L). YES NO

K. Customer Reference Number (CN): L. Regulated Entity Number (RN): II. General Information A. Is confidential information submitted with this application? If Yes , mark each confidential page confidential in large red letters at the bottom of each page. YES NO

B. Is this application in response to an investigation or enforcement action? If Yes , attach a copy of any correspondence from the agency. YES NO

C. Number of New Jobs: D. Provide the name of the State Senator and State Representative and district numbers for this facility site: Senator: District No.: Representative: District No.: III. Type of Permit Action Requested A. Mark the appropriate box indicating what type of action is requested. Initial Amendment Revision (30 TAC 116.116(e)) Change of Location Relocation B. Permit Number (if existing): C. Permit Type: Mark the appropriate box indicating what type of permit is requested. (check all that apply, skip for change of location) Construction Flexible Multiple Plant Nonattainment Prevention of Significant Deterioration Hazardous Air Pollutant Major Source Plant-Wide Applicability Limit Other: D. Is a permit renewal application being submitted in conjunction with this amendment in accordance with 30 TAC 116.315(c). YES NO



### 9 2 NE-A012-L

✔

CN603358771
RN105520779

✔

✔

70-85

Senator Juan "Chuy" Hinojosa 20 Representative Connie Scott 34

✔ 85013, PSD-TX-1138, HAP-48

✔ ✔

✔Texas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

III. Type of Permit Action Requested (continued) E. Is this application for a change of location of previously permitted facilities? If Yes, complete III.E.1 - III.E.4. YES NO
1. Current Location of Facility (If no street address, provide clear driving directions to the site in writing.): Street Address:

City: County: ZIP Code: 2. Proposed Location of Facilit y (If no street address, provide clear driving directions to the site in writing.): Street Address:

City: County: ZIP Code: 3. Will the proposed facility, site, and plot plan meet all current technical requirements of the permit special conditions? If No , attach detailed information. YES NO
4. Is the site where the facility is moving considered a major source of criteria pollutants or HAPs? YES NO

F. Consolidation into this Permit: List any standard permits, exemptions or permits by rule to be consolidated into this permit including those for planned maintenance, startup, and shutdown. List:

G. Are you permitting planned maintenance, startup, and shutdown emissions? If Yes , attach information on any changes to emissions under this application as specified in VII and VIII. YES NO

H. Federal Operating Permit Requirements (30 TAC Chapter 122 Applicability) Is this facility located at a site required to obtain a federal operating permit? If Yes , list all associated permit number(s), attach pages as needed). YES NO To be determined
Associated Permit No (s.): 1. Identify the requirements of 30 TAC Chapter 122 that will be triggered if this application is approved. FOP Significant Revision FOP Minor Application for an FOP Revision To Be Determined Operational Flexibility/Off-Permit Notification Streamlined Revision for GOP None

TCEQ – 10252 (Revised 06/11) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v16) Page _____ of _____ 

### 3 9 ✔

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✔

✔Texas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

III. Type of Permit Action Requested (continued) H. Federal Operating Permit Requirements (30 TAC Chapter 122 Applicability) (continued) 2. Identify the type(s) of FOP(s) issued and/or FOP application(s) submitted/pending for the site. (check all that apply) GOP Issued GOP application/revision application: submitted or under APD review SOP Issued SOP application/revision application submitted or under APD review IV. Public Notice Applicability A. Is this a new permit application or a change of location application? YES NO B. Is this application for a concrete batch plant? If Yes, complete V.C.1 – V.C.2. YES NO C. Is this an application for a major modification of a PSD, nonattainment, FCAA 112(g) permit, or exceedance of a PAL permit? YES NO

D. Is this a state permit amendment application? If Yes, complete IV.D.1. – IV.D.3. YES NO 1. Is there any change in character of emissions in this application? YES NO 2. Is there a new air contaminant in this application? YES NO 3. Do the facilities handle, load, unload, dry, manufacture, or process grain, seed, legumes, or vegetables fibers (agricultural facilities)? YES NO

E. List the total annual emission increases associated with the application ( list all that apply and attach additional sheets as needed ): Volatile Organic Compounds (VOC): Sulfur Dioxide (SO 2 ): Carbon Monoxide (CO): Nitrogen Oxides (NO x ): Particulate Matter (PM): PM 10 microns or less (PM 10 ): PM 2.5 microns or less (PM 2.5 ): Lead (Pb): Hazardous Air Pollutants (HAPs): Other speciated air contaminants not listed above:

TCEQ – 10252 (Revised 06/11) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v16) Page _____ of _____ 

### 4 9 ✔ ✔ ✔

✔Texas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

V. Public Notice Information (complete if applicable) A. Public Notice Contact Name: Title: Mailing Address: City: State: ZIP Code: Telephone No.: Fax No.: E-mail Address: B. Name of the Public Place: Physical Address (No P.O. Boxes): City: County: ZIP Code: Telephone No.: Fax No.: E-mail Address: The public place has granted authorization to place the application for public viewing and copying. YES NO The public place has internet access available for the public. YES NO C. Concrete Batch Plants, PSD, and Nonattainment Permits 1. County Judge Information (For Concrete Batch Plants and PSD site. and/or Nonattainment Permits) for this facility

The Honorable: Mailing Address: City: State: ZIP Code: Telephone No.: Fax No.: E-mail Address: 2. Is the facility located in a municipality or an extraterritorial jurisdiction (For Concrete Batch Plants) of a municipality? YES NO
Presiding Officers Name(s) ( Mr. Mrs. Ms. Dr.): Title: Mailing Address: City: State: ZIP Code: Telephone No.: Fax No.: E-mail Address:

TCEQ – 10252 (Revised 06/11) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v16) Page _____ of _____ 

### 5 9 N/ATexas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

V. Public Notice Information (complete if applicable) (continued) 3. Provide the name, mailing address of the chief executives of the city and county, State, Federal Land Manager, or Indian Governing Body for the location where the facility is or will be located. Chief Executive: Mailing Address: City: State: ZIP Code: Telephone No.: Fax No.: E-mail Address: Name of the State or Federal Land Manager ( Mr. Mrs. Ms. Dr.): Title: Mailing Address: City: State: ZIP Code: Telephone No.: Fax No.: E-mail Address: Name of the Indian Governing Body ( Mr. Mrs. Ms. Dr.): Title: Mailing Address: City: State: ZIP Code: Telephone No.: Fax No.: E-mail Address: D. Bilingual Notice Is a bilingual program required by the Texas Education Code in the School District? YES NO Are the children who attend either the elementary school or the middle school closest to your facility eligible to be enrolled in a bilingual program provided by the district? YES NO

If Yes , list which languages are required by the bilingual program?

VI. Small Business Classification (Required) A. Does this company (including parent companies and subsidiary companies) 100 employees or less than $6 million in annual gross receipts? have fewer than YES NO

B. Is the site a major stationary source for federal air quality permitting? YES NO C. Are the site emissions of any regulated air pollutant greater than or equal to 50 tpy? YES NO D. Are the site emissions of all regulated air pollutants combined less than 75 tpy? YES NO

TCEQ – 10252 (Revised 06/11) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v16) Page _____ of _____ 

### 6 9 ✔

✔ ✔ ✔Texas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

VII. Technical Information A. The following information included everything) must be submitted with your Form PI-1 (this is just a checklist to make sure you have

1. Current Area Map 2. Plot Plan 3. Existing Authorizations 4. Process Flow Diagram 5. Process Description 6. Maximum Emissions Data and Calculations 7. Air Permit Application Tables a. Table 1(a) (Form 10153) entitled, Emission Point Summary b. Table 2 (Form 10155) entitled, Material Balance c. Other equipment, process or control device tables B. Are any schools located within 3,000 feet of this facility? YES NO C. Maximum Operating Schedule: Hours: Day(s): Week(s): Year(s): Seasonal Operation? If Yes, please describe in the space provide below. YES NO

D. Have the planned MSS emissions been previously submitted as part of an emissions inventory? YES NO
Provide a list of each planned MSS facility or related activity and indicate included in the emissions inventories. Attach pages as needed. which years the MSS activities have been

E. Does this application involve any air contaminants for which a disaster review is required? YES NO F. Does this application include a pollutant of concern on the Air Pollutant Watch List (APWL )? YES NO VIII. State Regulatory Requirements Applicants must demonstrate compliance with all applicable state regulations to obtain a permit or amendment . The application must contain detailed attachments addressing applicability or non applicability; identify state regulations; show how requirements are met; and include compliance demonstrations. A. Will the emissions from the proposed facility protect public health and welfare, and comply with all rules and regulations of the TCEQ? YES NO

B. Will emissions of significant air contaminants from the facility be measured? YES NO C. Is the Best Available Control Technology (BACT) demonstration attached? YES NO

TCEQ – 10252 (Revised 06/11) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v16) Page _____ of _____ 

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✔ ✔ ✔ ✔

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✔ ✔Texas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

VIII. State Regulatory Requirements (continued) Applicants must demonstrate compliance with all applicable state regulations to obtain a permit or amendment
. The application must contain detailed attachments addressing applicability or non applicability; identify state regulations; show how requirements are met; and include compliance demonstrations. D. Will the proposed facilities achieve the performance represented in the permit application as demonstrated through recordkeeping, monitoring, stack testing, or other applicable methods? YES NO

IX. Federal Regulatory Requirements Applicants must demonstrate compliance with all applicable federal regulations to obtain a permit or amendment The application must contain detailed attachments addressing applicability or non applicability; identify federal regulation subparts; show how requireme nts are met; and include compliance demonstrations. A. Does Title 40 Code of Federal Regulations Part 60, (40 CFR Part 60) New Source Performance Standard (NSPS) apply to a facility in this application? YES NO

B. Does 40 CFR Part 61, National Emissions Standard for Hazardous Air Pollutants (NESHAP) apply to a facility in this application? YES NO

C. Does 40 CFR Part 63, Maximum Achievable Control Technology (MACT) standard apply to a facility in this application? YES NO

D. Do nonattainment permitting requirements apply to this application? YES NO E. Does prevention of significant deterioration permitting requirements apply to this application? YES NO

F. Do Hazardous Air Pollutant Major Source [FCAA 112(g)] requirements apply to this application? YES NO

G. Is a Plant-wide Applicability Limit permit being requested? YES NO X. Professional Engineer (P.E.) Seal Is the estimated capital cost of the project greater than $2 million dollars? YES NO If Yes , submit the application under the seal of a Texas licensed P.E. XI. Permit Fee Information Check, Money Order, Transaction Number ,ePay Voucher Number: Fee Amount: $ Company name on check: Paid online?: YES NO Is a copy of the check or money order attached to the original submittal of this application? YES NO N/A
Is a Table 30 (Form 10196) entitled, Estimated Capital Cost and Fee Verification, attached? YES NO N/A

TCEQ – 10252 (Revised 06/11) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v16) Page _____ of _____ 

### 8 9 ✔

✔

✔

✔ ✔

✔

✔

✔

N/AXII. Texas Commission on Environmental Quality Form PI-! General Application for Ail' Preconstrllction Permit and Amendment

Delinquent Fees And Penalties This form will not be processed until all delinquent fees and/or penalties owed to the TCEQ 01' the Office of the Attorney General on behalf of the TCEQ is paid in accordance with the Delinquent Fee and Penalty Protocol. For more information regarding Delinquent Fees and Penalties, go to the TCEQ Web site at:
www
. t ce q

. t ex a s

. gov/age n cy/ d e lin / ind ex

. h t m l. XIII. Signature The signature below confmns that I have knowledge of the facts included in this application and that these facts are true and correct to the best of my knowledge and belief. I fhrther state that to the best of my knowledge and belief, the project for which application is made will not in any way violate any provision of the Texas Water Code (TWC), Chapter 7, Texas Clean Ail' Act (TCAA), as amended, 01' any of the ail' quality rules and regulations of the Texas Conunission on Environmental Quality 01' any local governmental ordinance 01' resolution enacted pursuant to the TCAA I nu·ther state that I understand my signature indicates that tltis application meets all applicable nonattainment, prevention of significant deterioration, or major source of hazardous air pollutant permitting requirements. The signature nu·ther signifies awareness that intentionally or knowingly making or causing to be made false material statements 01' representations in the application is a criminal offense subject to criminal penalties.

Name:**~** 

# --lIJAJ**thUltl~/./**

Signature: 

# //w/ 

# I**~** 

# L ./( Original Signa/lire Reqllired 

### •

Date: 

# /-0 , 

## 2 

# <fJ. 

# '2- D//

TCEQ -10252 (Rc\ ' Jscd 06/11) PI·t Form This form Is for usc- by fncllitics subject to nlr quality permit rccluircl1Icllts find may be rC"ised periodically. (APDG 517h'16) 

### 9 9 Pngc

_ _ or

__P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 14 

## 2.0 P ROJECT 

## S COPE



### 2.1 P LANT 

### D ESIGN 

### C ONSIDERATIONS The proposed facility will consist of four 300

- MWe (nominal output) CFB boilers that are designed to use petroleum coke as fuel. The steam produced from the boilers will be routed to two single turbine generator sets. The power generated will be sold to regional load serving entities for resale via the local electricity transmission and distribution grid.
Petroleum coke, the exclusive fuel permitted for use by the LBEC, is a carbonaceous solid derived from oil refinery coker units or other cracking processes. The use of petroleum coke is fundamental to the Las Brisas’ business plan. Specifically, the location for the project has been selected because of its proximity to petroleum coke producers in the region. These producers are also potential significant power customers, and the ability for LBEC to off

- take petroleum coke in exchange for power purchases is fundamental to the project

. Locating Las Brisas close to the source of petroleum coke provides for lower costs associated with transportation of the petroleum coke . Also, because present users of the petroleum coke are more remote from the producing refineries, there will necessarily be a reduction of the GHG emissions associated with present transportation of the fuel to current users

. A process flow diagram is included as Figure IX

- C

- 1.

Las Brisas proposes to use circulating fluidized bed (CFB) technology for the power boilers. The pulverized coal

- fired (PC) boiler is the technology predominantly used at existing U.S. electric utility solid fuel

- firing power plants. Fluidized bed combustion is a newer technology that can be considered as an alternative to building a n ew PC

- fired electric generating unit EGU, depending on project specific requirements. The term "fluidized" refers to the state of the bed materials (fuel and inert material) as gas passes through the bed. In a typical fluidized bend combustion ( FBC ) EGU, combustion occurs when fuel and a sorbent, such as limestone, are suspended through the action of primary combustion air distributed below the combustor floor. The gas cushion between the solids allows the particles to move freely, giving the bed a liquid

like characteristic (i.e., fluidized). FBC can occur in either atmospheric or pressurized boilers. Two fluidized bed designs can be used for atmospheric and pressurized FBC boilers: a bubbling fluidized bed or a CFB

. The primary reason for selection of CFB technology for the Las Brisas project is that it has the ability to more efficiently burn 100% petroleum coke. E ven though the combustion temperature of a CFB boiler is low er than a PC boiler , the circulation of hot particles provides efficient heat tr ansfer to the furnace walls and allows longer residence time for carbon combustion and limestone reaction. Thus, a CFB can more efficiently burn any type and rank of solid fossil fuel, and performs better than PC technology with low volatility fuels, such as petroleum coke (lower volatility presents flame stability issues in PC boilers).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 15 CFB boiler s , like PC boilers, can be used with either subcritical or supercritical steam cycles

. LBEC selected a subcritical design for its CFB units because it is a more mature design that has demonstrated a known reliability and operational cost history. When Las Brisas submitted its State and PSD air permit application in May 2008, no supercritical CFB units were in operation and, even now, only one is ope rating worldwide a 460 MWe unit at a power plant owned by the Polish utility company Południowy Koncern Energetyczny SA (PKE) in Lagisza, Poland

. This plant, which burns a different fuel, b ituminous c oal , began operation in June 2009. Considering that on ly one supercritical CFB unit is in operation and only a small amount of o perational data to document the reliability and operational costs of the KKE unit is available, supercritical steam technology is not a consideration for Las Brisas in the selection of boiler technology. Additionally, it is not clear whether the supercritical steam CFB technology could reduce NOx and SO 2 emissions at required BACT levels without the addition of an SCR , which has been determined to not be technically feasible for the LBEC in the proceedings before the TCEQ

. T he PKE plant was permitted at the following emission limits: 200 mg/m 3 n @ 6% O 2 , dry for both NOx and SO 2 . 3 This equates to 0.17 lb/MMBtu for both NOx and SO 2 , utilizing the Fd Factor for Bituminous Coal of 9,780 dscf/MMBtu 4 . The PKE NOx emission limit of 0.17 lb/MMBtu is approximately 2.4 times higher than the annual average NOx limit for LBEC of 0.07 lb/MMBtu. The PKE SO 2 emission limit of 0.17 lb/MMBtu is approximately 2 ti mes higher than the annual average SO 2 limit for LBEC of 0.086 lb/MMBtu

Pressurized Fluidized

- Bed Combustion (PFBC) is another technology that has been employed in recent years. These systems typically operate at elevated pressures of 1 to 1.5 MPa (145 t o 218 psia) and produce a high pressure gas stream that can drive a turbine. Similar to the atmospheric pressure CFB, as that proposed for LBEC, the fuel and sorbent (for SO 2 reduction) are introduced into the boiler together. However the combustor and c yclones are enclosed in a pressure vessel and the crushed fuel and sorbent, as well as the ash, must be fed across a pressure boundary. Combustion temperatures of the PFBC boiler are similar to that of the atmospheric (1,500 to 1,650 o F).
Demonstration p rojects ranging in size from 60 MW to 130 MW were constructed and operated in the 1990’s in areas of Europe and the United States. Japanese equipment manufacturers and electric utility companies have constructed and are currently operating other PFBC faci lities three areas of the country. The largest of these units is the 360MW unit in Kitakyushu, Japan operated by the Kyushu Electric Power Company. Chugoku Electric Power Company operates a 250 MW unit and Hokaido Electric Power Company operates a smalle r 85 MW unit. All of these facilities have been designed to utilize coal as the fuel source. Petroleum coke has been fired in a PFBC boiler in a test facility in Sweden. However, the PFBC technology has not been proven with petroleum coke as a fuel sour ce for a utility scale boiler. In addition to the

3 Lagisza 460 MWe Supercritical CFB Design, Start

- up and Initial Operation Experience , Foster Wheeler, Oct. 2009

4 40 CFR 60, Appendix A, Reference Method 19, Table 19

- 2.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 16 unproven boiler technology, the gas turbine provided for the Kitakyushu facility, at 75 MW, is the largest ever built as a prototype. Given the fact that petroleum coke has not been proven in a utility sc ale PFBC boiler and the prototypical nature of the gas turbines, the PFBC technology is not a commercially viable alternative for LBEC. Another potential technology for power generation using petroleum coke is an integrated gasification combined cycle (I GCC) power plant. This technology integrates a fuel conversion plant (the gasification process) with a traditional combustion turbine

– steam turbine combined cycle power plant. The gasification process combines a feedstock, in this case petroleum coke, with steam in a low oxygen atmosphere at a high temperature and pressure to produce a “syngas” , which is then combusted in the gas turbines to generate electricity. Heat from the gasifiers and the combustion turbine exhaust is used to create steam that is then passed through a steam turbine to generate additional electricity. Although these two technologies have existed for many years, the integration of the two technologies, in an effort to achieve a higher efficiency, adds to the complexity of the pow er generation process. The syngas requires cooling and scrubbing prior to introducing it into the combustion turbine to protect the turbine and separate some of the polluting constituents. The combustion turbine also requires modification to burn the low Btu syngas (about 1⁄4 that of natural gas) and the syngas must be mixed with nitrogen to lower the flame temperature and resultant NOx production which further reduces the Btu value of the fuel. The gasification process as well as the high temperatures, hi gh pressures, and additional equipment result in shortened maintenance intervals of the equipment and thus the availability of the facility is reduced.

IGCC facilities have been constructed and are currently operating. H istorically the availability of these generating stations has been very low in the first year of operation (ranging from less than 10% to 40%). The availability of these facilities have increased over time as the operational experiences has been extended; however there are few that have achieved an availability of 70% or greater and only one has achieved an availability of more than 80%. [ Source: EPRI, Dr. J. Phillips, “Integrated Gasification Combined Cycles with CO 2 Capture”, Stanford University Global Climate Change & Energy Project R esearch Symposium, June 13

- 16, 2005. ] The Las Brisas Energy Center will have an availability of 92% or greater beginning the first year of operation. As indicative of industry information, the most advanced IGCC development that is still being pursued is the Duke Energy, Edwardsport facility. The reported cost of this proposed 630 MW IGCC project is now $2. 8 8 billion 5

5 Duke Energy, Edwardsport IGCC Plant Fact Sheet (excluding financing costs) which is equivalent to a cost of $4,730 per kilowatt (kW) with a scheduled commercial operation date in 2012. Early cost estimates for the project were approximately $1 billion lower (at $1.985 billion) than i s currently being experienced. Current costs are from an update provided by Duke Energy during the 3rd

http://www.duke

- energy.com/pdfs/IGCC

- Fact

- sheet

- 12.10.pd f (last visited 10/27/2011)P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 17 Quarter of 2011. Using the current cost information, this IGCC facility will be constructed at a 97% premium on a $/kW basis over the CFB installation planned for the Las Brisas facility. Cost reports for other IGCC projects include an estimated cost of $2.4 billion 6 ($4,123/kW) for the Kemper IGCC project being developed by Mississippi Power , with a planned in

- service date of 2014. This is a 582 MW lignite fueled IGCC in Mississippi. The construction costs for this facility is a 72% premium over the Las Brisas Proj ect. The project has received approximately $300 million in federal funds and has set a cap on the potential project costs of $3.2 billion or roughly $5,500/kW. Similarly, the latest estimates in 2010 for the Tenaska Taylorville IGCC project in Illinois were capped at $3.5 billion 7

In summary, Las Brisas has chosen to utilize subcritical CFB boiler technology for its power generation equipment for the following reasons: , or $5,800/kW for this 602 MW installation. In general terms, this data indicates that there is still a significant degree of uncertainty regarding IGCC pr oject costs. There is however, a clear indication that IGCC constructi on is expected to be at a significant cost premium. In a deregulated market as exists in Texas, a facility with this cost premium and reliability concerns would not be able to compete in the market.

**•** CFB boilers provide the ability to more efficiently burn the petroleum coke that is the basis for Las Brisas

. **•** Even though the combustion temperature of a CFB i s low, the fuel residence time is higher than that of a PC, which results in high combustion efficiencies.

**•** Subcritical technology has been proven to be reliable and cost effective, wh ile little operational data exist to support the use of supercritical tec hnology

.


### 2.2 C FB B OILERS
Las Brisas will include four 300

- MWe (nominally rated) CFB boilers that will use petroleum coke as fuel. During startup, natural gas and/or propane will be used prior to firing of the petroleum coke. The first two CFB boilers (Emission Point Number (EPN) CFB

- 1 and CFB

- 2) will drive one of the single steam turbine

- generator sets. The third and fo u rth CFB Boilers (EPN CFB

- 3 and CFB

- 4) will feed steam to a second single steam turbine

- generator.



### 2.3 A UXILIARY 

### B OILERS Two nominally r ated 180 MMBtu/hr auxiliary boilers (EPNs AUX

- BOIL1 and AUX

- BOIL2) will be utilized during start

- up and shutdown activities to provide auxiliary steam which may be required to stabilize the system. The boilers will be used during the commissioning phase o f the project

6 Mississippi Power, Kemper IGCC Brochure http://www.mississippipower.com/kemper/IGCC_BROCHURE.pdf (last visited 10/27/2011)

7 Tenaska News Release , July 1 3, 2009 http://www.tenaska.com/newsItem.aspx?id=62P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 18 (prior to normal operation) as well as during normal operation. Each auxiliary boiler will be limited to 2,500 hours of operation per year.



### 2.4 P ROP ANE 

### V AP ORIZERS Two nominally rated 16

- MMBtu/hr propane vaporizers (EPNs: PROP

- VAP1 and PROP

- VA P2) will be utilized as a source of CFB start

- up fuel in the event natural gas is not available. The vaporizers may be used during the commissioning phase of the project as well as during normal operation. Each vaporizer will be limited to 2,500 hours of operation per year.



### 2.5 D IESEL



### - F IRED 

### E MERGENCY 

### E QUIPMENT The site will be equipped with two nominally rated 1,600 kW diesel

- fired emergency generators (EPNs: ENG

- EG1and ENG

- EG

- 2) to provide electricity to the facility in case of power failure. A nominally rated 360

- HP diesel

- fired pump (EPN: ENG

- FWMAIN) will be installed at the site to provide water in the event of a fire. Four nominally rated 100

- HP diesel

- fired pumps (EPNs: ENG

- FWB1, ENG

- FWB2 , ENG

- FWB3, and ENG

- FWB4) will be installed at the site to serv e as fire water booster pumps at each of the CFB boilers. Four nominally rated 2,000

- HP diesel

- fired boiler feed water pumps (EPNs: ENG

- BFWP1, ENG

- BFWP2, ENG

- BFWP3, and ENG

- BFWP4) will be installed at the site to serve as emergency boiler feed water pump s at each of the CFB boilers. Each emergency engine will be limited to 100 hours operation per year for purposes of maintenance checks and readiness testing. Note that the emergency engines were authorized for 500 hours operation per year in TCEQ Permit No. 85013/ PSD

- TX

- 1138/HAP

- 48. However, New Source Performance Standards (NSPS) Subpart IIII

– Standards of Performance for Stationary Compression Ignition Internal Combustion Engines, limits the operation of emergency internal combustion engines to 100 hou rs per year for the purpose of maintenance checks and readiness testing. 8



### 2.6 E LECTRICAL 

### E QUIPMENT 

### I NSULATED WITH 

### S ULFUR 

### H EXAFLUORIDE 

### (SF 6 

### )

The generator circuit breaker s associated with the proposed CFB unit s will be insulated with SF 6 . SF 6 , a fluorinated compound that has an extremely stable molecular structure , is a colorless, odorless, non

- flammable, and non

- toxic synthetic gas. The unique chemical properties of SF 6 make it an efficient electrical insulator ; it is used for electrical insulation, arc que nching, and current interruption in high

- voltage electrical equipment. SF 6 is only used in sealed and safe systems which under normal circumstances do not leak gas. The capacity of the generator circuit breaker s associated with the proposed unit will be a pproximately 570 lb

. The proposed circuit breaker at the generator output will have a low pressure alarm and a low pressure lockout. The alarm will alert operating personnel to any leakage in the system and the lockout will prevent any operation of the b reaker due to lack of “quenching and cooling” SF 6 gas

.

8 40 CFR § 60.4211(e)

# •

•

• ...----- -- ---- (Typical for 2 Units) 

# I Water Treatment

TNK-BASE



### Caustic Tank

TNK-ACID 

### A

Acid Tank

WT-L1ME



### Lime Silo

WT-SODA 

### A Soda Ash Silo Trucks

Trucks 

# I I I I I 7**Steam ..-~-,** 

CTWR1 CTWR2 

# I Make-up Water Cooling Towers 

# I I I I I I I Blowdown



## J

Material BIN-SAND1 BIN-SAND2 BIN-SAND3 BIN-SAND4



### 4 Sand Day**~------~~----~** 

### Bins SILO-LMST1 SILO-LMST2 SILO-LMST3 SILO-LMST4



### Limestone ,-----------..J 

### Bun k e rs
From Storage and Processing (By Others) Transfer Tower 1-------. SILO-COKE1 thru SILO-COKES



### Pet. Coke**'------~** 

### Silos**~** 

### ___ --.J 

# L

TNK-FWMAIN TNK-EG1 TNK-EG2 TNK-FWB1 TNK-FWB2 TNK-FWB3 TNK-FWB4 ENG-BFWP1 ENG-BFWP2 ENG-BFWP3 ENG-BFWP4 

### Combustion Air

TNK-BFWP1 TNK-BFWP2 TNK-BFWP3 TNK-BFWP4 

### A

Diesel Tanks 1--'--,--' 

### Emergency Boiler Feed Pump Engines ENG-FWMAIN ENG-FWB1 ENG-FWB2 ENG-FWB3 ENG-FWB4



### Fire Water Pump Engines

ENG-EG1 ENG-EG2


### Emergency Generator

Engines Natural Gas FUG-NG 

### A 

# I I Steam Turbine

Circulating

Fluidized Bed Boiler Generator



# o FUG-NH3A FUG-NH3B



### Ammonia

Storage

Heat Recovery Electricity 

# I I I SILO-ACI1 SILO-ACI2 SILO-ACI3 SILO-ACI4



### Carbon

Silos Trucks

SILO-L1ME1 Thru SILO-LIMES



### Lime Silos Trucks



# ------ , ( T ypical for 4 Units) CFB1&2 CFB3&4 

# I I I I I Fabric Filter Polishing**r-~~ ~~**  

### S cru b be r '--r-------,--..------,r---<.-------r-'



### F or SILO-BA1 SILO-BA2 SILO-BA3 SILO-BA4



### Bottom Ash Silos '---------'>L...-_ 

### Boiler Feedwater

L----""--------..- 

### Boiler Blowdown

L-I

# ------I~~ To Trucks (By Others) To Trucks (By Others)

CFB St t a r- up AUX-BO I L1 AUX-BOIL2 

# t FUG-PROP1 FUG-PROP2 PROP-VAP1 PROP-VAP2 

# t
Auxiliary Boilers Steam Propane Storage & Vaporizers SILO-FA1 SILO-FA2 SILO-FA3 SILO-FA4


### Fly Ash

Silos

For CFB Start-up 

### __ ...J

KEY Emission Point 

# t 

# o Material Balance Numbe r



### Las Brisas Energy Cent e r, LLC Corpus Christi, Nueces County, TX 

### Figure 2-1 Process Flow Diagram

404 Camp Craft Rd.

Austin, TX 78746 

# ....... JDC

La s Bri s a s E x hibit 7 

## 00013

# --------------------- --- --- - -- -

----

""' CONVEYOR FROM

OFF-SITE MATERIAL STORAGE (BY OTHERS) NOTE: Diesel tanks EPNs are not shown. There is one tank adjacent to each engine.

200 300 4 00FT

o 20 40 60 so 100**120~ ~.......**  __ ;;;i!



### Las Brisas Energy Center, LLC Corpus Christi, Nueces County, TX

Figure 

### 3-2 Plot Plan

404 Camp Craft Rd Austin, TX 78746



## Las Brisas Exhibit 7 00016" Ii**~= «-** **i}**

\ 

### \. i-' ;!!!!!.:-_

. _- -

__ _ __ .... .:.0: ._ =
I / 

# .

Oft. 1200ft. 2000ft

.

# ~- 1-

Las Brisas Energy Center, LLC Corpus Christi, Nueces County, TX 

### Figure 3-1 Area Ma

404 Camp Craft Rd. Austin, TX 78746



## Las Brisas Exhibit 7 

## 00015 3-2P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 22 

## 3.0 GHG E MISSION 

## C ALCULATIONS



### 3.1 GHG E MISSIONS 

### F ROM 

### CFB B OILERS
CO 2 emissions from the combustion of petroleum coke in the CFB boilers are calculated using the emission factors (kg/MMBtu) for petroleum coke from Table C

- 1 of the Mandatory Greenhouse Gas Reporting Rules. 9 CH 4 and N 2 O emission calculations are calculated u sing the emission factors (kg/MMBtu) for petroleum coke from Table C

- 2 of the Mandatory Greenhouse Gas Reporting Rules. 10 The g lobal w arming p otential factors used to calculate CO 2 e emissions are based on Table A

- 1 of Mand atory Greenhouse Gas Reporting Rul es. 11

CO 2 emissions are generated from the use of the sorbent (crushed limestone) in the SO 2 removal system in the CFB boilers in the following manner:

**•** CO 2 is released from the reaction of CaCO 3 with SO 2 by the following reaction: CaCO 3 + SO 2  CaSO 3 + CO 2
**•** The remaining CaCO 3 in the limestone is decomposed due to the heat in the boiler by the following reaction: CaCO 3  CaO + CO 2
**•** The MgCO 3 in the limestone is decomposed due to the heat in the boiler by the following reaction: MgCO 3  MgO+ CO 2 . **•** Organic carbon compounds in the limestone are oxidized to produced H 2 O and CO 2 . CO 2 emissions from the use of CaCO 3 in the CFB boilers are calculated using equation G

- 5 of the Acid Rain Rules . Equation G

- 5 is used rather than equation G

- 6 b ecause equation G

- 5 is based on the total amount of CaCO 3 used and equation G

- 6 is based on ly on the amount of CaCO 3 stoichiometrically required based on the amount of SO 2 removed. A n excess of limestone will be added to the CFB boilers to promote the reaction and high remova l of SO 2 in the CFB bed . Using equation G

- 5 accounts to both the CO 2 released from the reaction of CaCO 3 with SO 2 and the CO 2 released from the excess CaCO 3 in the limestone decomposing in the boilers. Equation G

- 5 provides as follows: 12


### SE CO2 

### = W CaCO3 

### x Fu x MW CO2 

### /MW CaCO3 

### (Eq. G

- 5 )
Where:
SE CO2 

### = CO 2 

### emitted from sorbent, tons/yr.

W CaCO3 

### = CaCO 3 

### used, tons/yr Fu = 1.0, the calcium to sulfur stoichiometric ratio.

9 Default CO 2 Emission Factors and High Heat Values for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C

- 1

10 Default CH 4 and N 2 O Emission Factors for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C

- 2

11 Global Warming Potentials , 40 C.F.R. Pt. 98, Subpt. A, Tbl. A

- 1.

12 40 C.F.R. 75, Appendix G

– Determination of CO 2 EmissionsP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 23 

### MW CO2 

### = Molecular weight of carbon dioxide, 44.0 lb/lb

- mole.
MW CaCO3 

### = Molecular weigh t of CaCO 3 

### , 100 .0 lb/lb

- mole.

CO 2 emissions from the decomposition of the MgCO 3 in the limestone are based on the stoichiometric ratio of one mole of CO 2 generated for each mole of MgCO 3 added to the boiler

. This is consistent with the GHG reporting calcu lation method for Cement Production in 40 CFR 98, Subpart H, except that it is based on the amount of MgCO 3 input rather than the amount of MgO produced.

CO 2 emissions from the oxidation of organic carbon compounds in the limestone are based on the default factor of 0.2 wt% organic carbon content contained in 40 CFR 98, Subpart H, § 98.83(d)(3).
Calculations of GHG emissions from the CFB boilers are presented on Table 3

- 2.



### 3.2 GHG E MISSIONS 

### F ROM 

### A UXILIARY 

### B OILERS
CO 2 emissions from the na tural

- gas - fired auxiliary boilers are calculated using the emission factors (kg/MMBtu) for natural gas from Table C

- 1 of the Mandatory Greenhouse Gas Reporting Rules. 13 CH 4 and N 2 O emissions from the auxiliary boilers are calculated using the emission fact ors (kg/MMBtu) for natural gas from Table C

- 2 of the Mandatory Greenhouse Gas Reporting Rules. 14 The g lobal w arming p otential factors used to calculate CO 2 e emissions are based on Table A

- 1 of Mand atory Greenhouse Gas Reporting Rules. 15

Calculations of GHG emissions from the auxiliary boilers are presented on Table 3

- 3.



### 3.3 GHG E MISSIONS 

### F ROM 

### P ROP ANE 

### V AP ORIZERS
CO 2 emissions from the propane

- fired propane vaporizers are calculated using the emission factors (kg/MMBtu) for propane from Table C

- 1 of the Mandatory Greenhouse Gas Reporting Rules. 16 CH 4 and N 2 O emission from the propane vaporizers are calculated using the emission factors (kg/MMBtu) for propane from Table C

- 2 of the Mandatory Greenhouse Gas Reporting Rules. 17 The g lobal w arming p otential fac tors used to calculate CO 2 e emissions are based on Table A

- 1 of Mand atory Greenhouse Gas Reporting Rules. 18 Calculations of GHG emissions from the propane vaporizers are presented on Table 3

- 4.

13 Default CO 2 Emission Factors and High Hea t Values for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C

- 1

14 Default CH 4 and N 2 O Emission Factors for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C

- 2

15 Global Warming Potentials , 40 C.F.R. Pt. 98, Subpt. A, Tbl. A

- 1.

16 Default CO 2 Emission Factors and High Heat Values for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C

- 1

17 Default CH 4 and N 2 O Emission Factors for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C

- 2

18 Global Warming Potentials , 40 C.F.R. Pt. 98, Subpt. A, T bl. A

- 1.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 24 

### 3.4 GHG E MISSIONS 

### F ROM 

### N ATURAL 

### G AS 

### P IPING 

### F UGITIVES
GHG emission s from natural gas piping components are based on e mission factors from Table W

- 1A of the Mandatory Greenhouse Gas Reporting Rules. 19 The concentrations of CH 4 and CO 2 in the natural gas are based on a typical natural gas analysis. The g lobal w arming p oten tial factors used to calculate CO 2 e emissions are based on Table A

- 1 of Mand atory Greenhouse Gas Reporting Rules. 20 Calculations of GHG emissions from the natural gas piping components are presented on Table 3

- 5.



### 3.5 GHG E MISSIONS 

### F ROM 

### D IESEL 

### F IRED 

### E MERGENCY 

### E NGINES
CO 2 emission calculations from the diesel

- fired emergency generators, fire pump engines and the emergency boiler feed water pump engines are calculated using the emission factors (kg/MMBtu) for Distillate Fuel Oil No. 2 from Table C

- 1 of the Mandat ory Greenhouse Gas Reporting Rules. 21 CH 4 and N 2 O emission calculations from the diesel

- fired engines are calculated using the emission factors (kg/MMBtu) for Petroleum from Table C

- 2 of the Mandatory Greenhouse Gas Reporting Rules. 22 The g lobal w arming p o tential factors used to calculate CO 2 e emissions are based on Table A

- 1 of Mand atory Greenhouse Gas Reporting Rules. 23 Calculations of GHG emissions from the emergency engines are presented on Table 3

- 6.



### 3.6 GHG E MISSIONS 

### F ROM 

### E LECTRICAL 

### E QUIPMENT 

### I NSULATED W ITH 

### SF 6 SF 6 emissions from the new generator circuit breaker s associated with the proposed unit are calculated using a predicted SF 6 annual leak rate of 0.5% by weight. The global warming potential factors used to calculate CO 2 e emissions are based on Table A

- 1 of Mandatory Greenhouse Gas Reporting Rules. 24
Calculations of GHG emissions from electric equipment insulated with SF 6 are presented on Table 3

- 7.

19 Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production , 40 C.F.R. Pt. 98, Subpt. W, Tbl. W

- 1A.

20 Global Warming Potentials , 40 C.F.R. Pt. 98, Subpt. A, Tbl. A

- 1.

21 Default CO 2 Emission Factors and High Heat Values fo r Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C

- 1

22 Default CH 4 and N 2 O Emission Factors for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C

- 2

23 Global Warming Potentials , 40 C.F.R. Pt. 98, Subpt. A, Tbl. A

- 1.

24 Id.Table 3-1 Plantwide GHG PTE Emission Summary Las Brisas Energy Center LLC Corpus Christi, Nueces County, Texas

Status Name EPN GHG M ass Emissions CO 2 e ton/yr ton/yr New CFB Boiler 1 CFB-1 3,221,718 3,255,305 New CFB Boiler 2 CFB-2 3,221,718 3,255,305 New CFB Boiler 3 CFB-3 3,221,718 3,255,305 New CFB Boiler 4 CFB-4 3,221,718 3,255,305 New Auxilliary Boiler 1 AUX-BOIL1 26,312 26,337 New Auxilliary Boiler 2 AUX-BOIL2 26,312 26,337 New Propane Vaporizer 1 PRO-VAP1 2,711 2,721 New Propane Vaporizer 2 PRO-VAP2 2,711 2,721 New Emergency Generator 1 ENG-EG1-1 145 145 New Emergency Generator 2 ENG-EG1-2 145 145 New Fire Water Pump ENG-FWMAIN 23 23 New Fire Water Booster Pump ENG-FWB1 6 6 New Fire Water Booster Pump ENG-FWB2 6 6 New Fire Water Booster Pump ENG-FWB3 6 6 New Fire Water Booster Pump ENG-FWB4 6 6 New Boiler Feed Water Pump ENG-BFWP1 125 126 New Boiler Feed Water Pump ENG-BFWP2 125 126 New Boiler Feed Water Pump ENG-BFWP3 125 126 New Boiler Feed Water Pump ENG-BFWP4 125 126 New Natural Gas Piping Fugitives FUG-NG 3 61 New Insulated Electrical Equipment FUG-SF6 0.0014 34 12,945,757 13,080,273 TOTAL

10/28/2011Table 3-2GHG Emission Calculations - CFB BoilersLas Brisas Energy Center LLCGHG Potential To Emit Emissions From Coke Fired CFB BoilersGHG Emissions from fuel firingEPNFuel Use1Annual OperationMaximum Heat Input1Pollutant Emission FactorGHG MassEmissionsCO2e(MMBtu/hr coke) (hr/yr) (MMBtu/yr)(kg/MMBtu)2(tpy) (tpy)CO2102.04 3,034,765 1 3,034,765.13,080 8760 26,980,800CH41.1E-02 327.15 21 6,870.2N2O1.6E-03 47.59 310 14,751.5Totals 3,035,139.8 3,056,386.8Note1. Annual fuel usage from State/PSD air permit application2. Factors from Table C-1 and C-2 of 40 CFR Part 98, Mandatory Greenhouse Gas Reporting.3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.GHG Emissions from Limestone CalcinationCalculations are for each unitEPNMaximum HeatInputLimestoneUsed4CaCO3Used4MgCO3Used4CO2From CaCO35CO2FromMgCO36Total CO2CO2eEmission FactorFrom LimestoneCalcination(MMBtu/yr) TPY(tpy) (tpy) (tpy) (tpy)4(tpy)(tpy)kg CO2e/MMBtuCFB-1 through CFB-4(each unit)26,980,800 424,041 388,888 14,333 186,578 9,231 3,110 198,918 1 198,918 6.69Note4. Calculation of Limestone, CaCO3, MgCO3UsageFuel Sulfur =6.7 wt% (annual average)Fuel HHV =13,800 Btu/lbFuel Sulfur Input =4.86 lb S/MMBtuPotential SO2output =9.71lb SO2/MMBtuCa/S Ratio =1.90(an excess of limestone is added to promote the reaction and high removal of SO2in the CFB bed)CaCO3Usage =28.8lb CaCO3/MMBtuAvg. CaCO3wt% in Limestone =91.7% (From TCEQ PSD Application)Avg. MgCO3wt% in Limestone =3.4% (From TCEQ PSD Application)Limestone Usage = 31.43 lb limestone/MMBtuMgCO3Usage =1.06lb MgCO3/MMBtuGlobal WarmingPotential3CFB-1 through CFB-4(each unit)GlobalWarmingPotential3CO2FromOrganic Carbonin Limestone7(tpy)Page 1 of 210/28/2011Table 3-2GHG Emission Calculations - CFB BoilersLas Brisas Energy Center LLC5. SECO2= WCaCO3* Fu *MWCO2/MWCaCO3+ (40 CFR Part 75 Appendix G, Equation G-5)where,SECO2= CO2emitted from sorbent, ton/yrWCaCO3= CaCO3used, ton/yrFu = 1.0, the calcium to sulfur stoichiometric ratioMWCO2= molecular weight of CO2=44MWCaCO3= molecular weight of CaCO3=1006. CO2liberated from MgCO3MgCO3=> MgO + CO2CO2ton/yr =MgCO3ton2000 lblbmole MgCO31 lbmole CO244 lb CO2tonyr ton68.32 lb MgCO31 lbmole MgCO3lbmole CO22000 lb7. CO2Emissions from Organic Carbon Content of LimestoneOrganic Carbon Content of Limestone = 0.2 wt% default value from 40 CFR 98, Subpart H, Equation H-5CO2ton/yr =Limestone ton 2000 lb 0.002 lb C lbmole C1 lbmole CO244 lb CO2tonyr ton lb limestone 12 lb C 1 lbmole Clbmole CO22000 lbTOTAL GHG EmissionsEPN PollutantGHG MassEmissionsCO2e(tpy) (tpy)CO23,221,343 3,233,683.2CH4327 6,870.2N2O48 14,751.5Totals 3,221,717.7 3,255,304.8MSS Emissions ComparisonOperation Mode Fuel TypeFuel Use8Emission factor9Emission factor9Emission factor9Emissions Emissions EmissionsMMBtu/hr CO - lb/MMBtuCH4- lb/MMBtu N2O - lb/MMBtuCO -lb/hrCH4- lb/hr N2O - lb/hrNormal Operation coke 3080.0 224.96 0.0243 0.0035692,869 75 11coke 770.0 224.96 0.0243 0.0035 173,217 19 3natural gas 426.0 116.89 0.00220 0.00022 49,794 1 0223,011 20 3Normal operation emissions are larger.Note8. Start-up fuel use from permit application submitted May 2008.9. Factors based on Table C-1 and C-2 of 40 CFR Part 98, and converted to lbs from kg.Start-upTOTALCFB-1 through CFB-4(each unit)Page 2 of 210/28/2011Table 3-3 GHG Emission Calculations - Auxilliary Boilers Las Brisas Energy Center LLC

GHG Potential To Emit Emissions From Natural Gas Fired Auxilliary Boilers Calculations are for each unit
EPN Fuel Use 1 HHV of Fuel 1 Maximum Heat Input 1 Pollutant Emission Factor GHG Mass Emissions CO 2 e (MMscf/yr) (MMBtu/MMscf) (MMBtu/yr) (kg/MMBtu) 2 (tpy) (tpy) CO 2 53.02 26,310.99 1 26,311.0 453.8 992 450,192 CH 4 1.0E-03 0.50 21 10.4 N 2 O 1.0E-04 0.05 310 15.4 Totals 26,311.5 26,336.8

Note 1. Annual fuel use and heating value of natural gas from State/PSD air permit application 2. Factors based on Table C-1 and C-2 of 40 CFR Part 98, Mandatory Greenhouse Gas Reporting. 3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Global Warming Potential 3

AUX-BOIL1 and

AUX-BOIL2

10/28/2011Table 3-4 GHG Emission Calculations - Propane Vaporizers Las Brisas Energy Center LLC

GHG Potential To Emit Emissions From Propane Fired Vaporizers Calculations are for each unit
EPN Fuel Use 1 HHV of Fuel 1 Maximum Heat Input 1 Pollutant Emission Factor GHG Mass Emissions CO 2 e (MMscf/yr) (MMBtu/MMscf) (MMBtu/yr) (kg/MMBtu) 2 (tpy) (tpy) CO 2 61.46 2,710.44 1 2,710.4 15.745 2541 40,008 CH 4 3.0E-03 0.13 21 2.8 N 2 O 6.0E-04 0.03 310 8.2 Totals 2,710.6 2,721.4

Note 1. Annual fuel usage and heating value of propane from State/PSD air permit application 2. Factors based on Table C-1 and C-2 of 40 CFR Part 98, Mandatory Greenhouse Gas Reporting. 3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Global Warming Potential 3

PROP-VAP1 and

PROP-VAP1

10/28/2011Table 3-5 GHG Emission Calculations - Natural Gas Piping Las Brisas Energy Center LLC

GHG Emissions From New Natural Gas Piping Components

EPN Source Fluid Count Emission CO 2 2 Methane 3 Total Type State Factor 1 (tpy) (tpy) (tpy) scf/hr/comp Valves Gas/Vapor 100 0.123 0.123 2.13 FUG-NG Flanges Gas/Vapor 250 0.017 0.043 0.74 Relief Valves Gas/Vapor 1 0.196 0.002 0.03 GHG Mass-Based Emissions 0.17 2.90 3.1 Global Warming Potential 4 1 21 CO 2 e Emissions 0.17 60.88 61.1

Note 1. Emission factors from Table W-1A of 40 CFR 98 Mandatory Greenhouse Gas Reporting 2. CO 2 emissions based on vol% of CO 2 in natural gas 2.0% conservative estimate based on typical natural gas 3. CH 4 emissions based on vol% of CH 4 in natural gas 95.0% conservative estimate based on typical natural gas 4. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.

Example calculation: 100 valve 0.123 scf gas 0.02 scf CO 2 lbmole 44.01 lb CO 2 8760 hr ton = 0.12 ton/yr hr * valve scf gas 385.5 scf lbmole yr 2000 lb

10/28/2011Table 3-6 GHG Emission Calculations - Emergency Engines Las Brisas Energy Center LLC

GHG Emissions Contribution From Diesel Combustion In Emergency Engines Calculations are for each unit
Assumptions Generator Fire Water Pump Fire Water Booster

Pump Boiler Feed Water Pump Ann.Operating Schedule 100 100 100 100 hours/year Power Rating 2,309 360 100 2,000 hp Brake Specific Fuel Consumption 7,709 7,709 7,709 7,709 Btu/hp-hr Number of units 2 1 4 4

EPN Heat Input Pollutant Emission Factor GHG Mass Emissions CO 2 e (MMBtu/hr) (kg/MMBtu) 1 (tpy) (tpy) CO 2 73.96 144.8 1 144.8 17.8 CH 4 3.0E-03 0.01 21 0.1 N 2 O 6.0E-04 0.00 310 0.4 Totals 144.82 145.3 CO 2 73.96 22.6 1 22.6 ENG-FWMAIN 2.8 CH 4 3.0E-03 0.00 21 0.0 N 2 O 6.0E-04 0.000 310 0.1 Totals 22.58 22.7 CO 2 73.96 6.3 1 6.3 0.8 CH 4 3.0E-03 0.0 21 0.0 N 2 O 6.0E-04 0.0 310 0.0 Totals 6.27 6.3 CO 2 73.96 125.4 1 125.4 15.4 CH 4 3.0E-03 0.0 21 0.1 N 2 O 6.0E-04 0.0 310 0.3 Totals 125.44 125.9

Calculation Procedure Annual Emission Rate = heat Input x Emission Factor x 2.2 lbs/kg x hours/year x Global Warming Potential / 2,000 lbs/ton

Note 1. GHG factors based on Tables C-1 and C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 2. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Global Warming Potential 2
ENG-EG1 & 2 (each unit)

ENG-FWB1 to 4 (each unit)

ENG-BFWP1 to 4 (each unit)

10/28/2011Table 3-7 GHG Emission Calculations - Electrical Equipment Insulated With SF 6 Corpus Christi, Nueces County, Texas

Assumptions New insulated circuit breaker SF 6 capacity 570 lb Estimated annual SF 6 leak rate 0.5% by weight Estimated annual SF 6 mass emission rate 0.001425 ton/yr Global Warmin g Potential 1 23,900 Estimated annual CO 2 e emission rate 34.1 ton/yr

Note 1. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.

10/28/2011P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 33 

## 4.0 P REVENTION OF 

## S IGNIFICANT 

## D ETERIORATION 

## A PPLICABILITY

Bec ause the project emissions increase of GHG is greater than 75,000 ton/yr of CO 2 e, PSD is triggered for GHG emissions. The emissions netting analysis is documented on the attached TCEQ PSD netting tables: Table 1F and Table 2F

. Note that this is a new greenfield site and, as such, there are no contemporaneous emission changes associated with the project. Also included in Appendix B is the “The GHG PSD APPLICABILI TY FLOWCHART

– NEW SOURCES” from the PSD and Title V Permitting Gui dance for Greenhouse Gases

.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 34 

## TCEQ PSD NETTING TABLESTAUL E IF AIR Q U ALln ' APPLI CA TION**SU PPL** **~IENT**

P e nn it No.: 85013 , PS D-T X-1 1 38, H A P 48 I A p pl i ca ti o li Sub mittal D a t e: Company La s B r isas E ncrg} ' Ce n te r LI.C RN: RN 1 05520779 Faci li ty Locn ti o n : Co r pus C hr is ti C it y Co rpu s C llTi s li Cm 1llt y: N u eces P er mit U ni t J.D .: 0 11 u nits P en n i! Na m e: E le ct ri c Ge n eratio n Faci lit y Permi t Ac ti vit\' : 

### o Il ew t·1ajor Source D / ·\odiflcatloo Pro

je c t o r Proce ss Dc sc ri )I i on: A u t h o ri ze n e w C FB bo il ers a nd a n ci ll ary eq ui pme nt

C omplete fol'**~II** fl o llutnlli s wilh a IJroject POLL U TANT S

e mi ss ion incl' e a s e

. Ozon e C O S O , 1' 1\ I NOx I VO C No natlainm e nt ? (ye s or no) I Ex i sti n g si t e P

TE ( I py) Thi s f orm for GIIG only Proposed project**ncr~ 'as"s**  (tpy f rom 2fi I s I

he ex i st in g si t e a m a jor so urce? If nO l , is I he pro jec t a m

ajor s ourc e b y i tself? (ycs or no) Ye s l f si t e is m ajor , i s p r ojec t i n c r

ease s i gni l1 cant? (ye s o r no) I I I I fil C Hi ng r e q uired, es t i m ate d sta rt of co n s tm c t ion : 1 11 1 112 5 years p ri o r t o s t art of con s truc t ion : 11 /2/ 07 C on t empo m neou s
es tim ated s t a rt of opcrn t io n : 1111 1 7 P er i

o d Nc t c on te m poraneous cha n ge, i nclu din g pr opose d projec t , fro m Tab l e 3F ( t py) FNS R ap p l icable? (ye s or 110)

I

. O th er P SD p o llut a nt s 2. No n a ll a illlll c nim ajor S O

llr ce is d efi n ed i n Tab l e 1 in 30 T AC 11 6. 1 2( 11 ) b y po llul m ll a n d coull t y
. PSD t hr es h o l d s

a r e f O ll n d i n · I O eFR § S 1.1 66(b) ( J ). 3. Su m of pr opo se d emi ss ions m inu s base l ine em i ss i ons , i ncreases on l y. Nona tl a i nmcn t thr es h o l ds a r c found in T ab l e 1 in 30 TAC 11 6. 1 2( 11 ) and P S D th re s h o ld s ill 40 C FR §5 I.1 GG(b)(23)

. GII G

No 0 12 ,945,757

Ye s

12 ,945,757 Yes

D a t e C O l e

No 0 1 3,080)73

Yes

1 3,080)73

Ye sTABLE 2FPROJECT EMISSION INCREASEPollutant(1): GHG Permit: Electric Generation FacilityBaseline Period: N/Ato N/AA BAffected or Modified Facilities(2)PermitNo.ActualEmissions(3)BaselineEmissions(4)ProposedEmissions(5)ProjectedActualEmissionsDifference(A-B)(6)Correction(7)ProjectIncrease(8)FIN EPN1CFB-1 CFB-1850130 0 3,221,718 3,221,718 3,221,7182CFB-2 CFB-285013 0 0 3,221,718 3,221,718 3,221,7183CFB-3 CFB-385013 0 0 3,221,718 3,221,718 3,221,7184CFB-4 CFB-485013 0 0 3,221,718 3,221,718 3,221,7185AUX-BOIL1 AUX-BOIL185013 0 0 26,312 26,312 26,3126AUX-BOIL2 AUX-BOIL285013 0 0 26,312 26,312 26,3127PRO-VAP1 PRO-VAP185013 0 0 2,711 2,711 2,7118PRO-VAP2 PRO-VAP285013 0 0 2,711 2,711 2,7119ENG-EG1-1 ENG-EG1-185013 0 0 145 145 14510ENG-EG1-2 ENG-EG1-285013 0 0 145 145 14511ENG-FWMAIN ENG-FWMAIN85013 0 0 23 23 2312ENG-FWB1 ENG-FWB185013 0 0 6 6 613ENG-FWB2 ENG-FWB285013 0 0 6 6 614ENG-FWB3 ENG-FWB385013 0 0 6 6 615ENG-FWB4 ENG-FWB485013 0 0 6 6 616ENG-BFWP1 ENG-BFWP185013 0 0 125 125 12517ENG-BFWP2 ENG-BFWP285013 0 0 125 125 12518ENG-BFWP3 ENG-BFWP385013 0 0 125 125 12519ENG-BFWP4 ENG-BFWP485013 0 0 125 125 12520FUG-NG FUG-NG85013 0 0 3 3 321FUG-SF6 FUG-SF685013 0 0 0.0014 0.0014 0.0014Total 12,945,7571. Individual Table 2F's should be used to summarize the project emission increase for each criteria pollutant.2. Emission Point Number as designated in NSR Permit or Emissions Inventory.3. All records and calculations for these values must be available upon request.4. Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well asany MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement.5. If projected actual emission is used it must be noted in the next column and the basis for the projection identified in theTable2F supplement.6. Proposed Emissions (column B) - Baseline Emissions (column A).7. Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification andbasis for this estimate must be provided in the Table 2F supplement.8. Obtained by subtracting the correction from the difference. Must be a positive number.9. Sum all values for this page.TABLE 2FPROJECT EMISSION INCREASEPollutant(1): CO2e Permit: Electric Generation FacilityBaseline Period: N/Ato N/AA BAffected or Modified Facilities(2)PermitNo.ActualEmissions(3)BaselineEmissions(4)ProposedEmissions(5)ProjectedActualEmissionsDifference(A-B)(6)Correction(7)ProjectIncrease(8)FIN EPN1CFB-1 CFB-1850130 0 3,255,305 3,255,305 3,255,3052CFB-2 CFB-285013 0 0 3,255,305 3,255,305 3,255,3053CFB-3 CFB-385013 0 0 3,255,305 3,255,305 3,255,3054CFB-4 CFB-485013 0 0 3,255,305 3,255,305 3,255,3055AUX-BOIL1 AUX-BOIL185013 0 0 26,337 26,337 26,3376AUX-BOIL2 AUX-BOIL285013 0 0 26,337 26,337 26,3377PRO-VAP1 PRO-VAP185013 0 0 2,721 2,721 2,7218PRO-VAP2 PRO-VAP285013 0 0 2,721 2,721 2,7219ENG-EG1-1 ENG-EG1-185013 0 0 145 145 14510ENG-EG1-2 ENG-EG1-285013 0 0 145 145 14511ENG-FWMAIN ENG-FWMAIN85013 0 0 23 23 2312ENG-FWB1 ENG-FWB185013 0 0 6 6 613ENG-FWB2 ENG-FWB285013 0 0 6 6 614ENG-FWB3 ENG-FWB385013 0 0 6 6 615ENG-FWB4 ENG-FWB485013 0 0 6 6 616ENG-BFWP1 ENG-BFWP185013 0 0 126 126 12617ENG-BFWP2 ENG-BFWP285013 0 0 126 126 12618ENG-BFWP3 ENG-BFWP385013 0 0 126 126 12619ENG-BFWP4 ENG-BFWP485013 0 0 126 126 12620FUG-NG FUG-NG85013 0 0 61 61 6121FUG-SF6 FUG-SF685013 0 0 34 34 34Total 13,080,2731. Individual Table 2F's should be used to summarize the project emission increase for each criteria pollutant.2. Emission Point Number as designated in NSR Permit or Emissions Inventory.3. All records and calculations for these values must be available upon request.4. Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well asany MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement.5. If projected actual emission is used it must be noted in the next column and the basis for the projection identified in theTable2F supplement.6. Proposed Emissions (column B) - Baseline Emissions (column A).7. Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification andbasis for this estimate must be provided in the Table 2F supplement.8. Obtained by subtracting the correction from the difference. Must be a positive number.9. Sum all values for this page.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 38 

## 5.0 B EST 

## A VAILABLE 

## C ONTROL 

## T ECHNOLOGY 

## (BACT)

5.1 D EFINITION OF 

### BACT

The EPA’s BACT requirements are set forth in section 165(a)(4) of the Clean Air Act and in federal regulation at 40 CFR 52.21. 40 CFR 52.21 defines Best Available Control Technology as: Best available control technology means an emissions limitation (including a visible emission standard) based on the maximum degree of reduc tion for each pollutant subject to regulation under Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case

- by

- case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall application of best available control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61. If the Administrator determines tha t technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combination the reof, may be prescribed instead to satisfy the requirement for the application of best available control technology. Such standard shall, to the degree possible, set forth the emissions reduction achievable by implementation of such design, equipment, wor k practice or operation, and shall provide for compliance by means which achieve equivalent results. 25 In the EPA guidance document titled PSD and Title V Permitting Guidance for Greenhouse Gases , EPA recommended the use of the Agency’s five

- step “top

- down ” BACT process to determine BACT for GHGs. 26 In brief, the top

- down process calls for all available control technologies for a given pollutant to be identified and ranked in descending order of control effectiveness. The permit applicant should first exam ine the highest

- ranked (“top”) option and t he top

- ranked options should be established as BACT unless the permit applicant demonstrates to the satisfaction of the permitting authority that technical considerations, or energy, environmental, or economic imp acts justify a conclusion that the top ranked technology is not “achievable” in that case. If the most effective control strategy is eliminated in this fashion, then the next most effective alternative should be evaluated, and so on, until an option is se lected as BACT.
EPA has broken down this analytical process into the following five steps:

25 40 C

. F

. R

. § 52.21(b)( 12.)

26 EPA, PSD and Title V Permitting Guidance for Greenhouse Gases , p. 18 (Mar. 201 1).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

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010303 39 Step 1: Identify all available control technologies. Step 2: Eliminate technically infeasible options. Step 3: Rank remaining control technologies. Step 4: Evaluate most effective controls and document results. Step 5: Select the BACT.



### 5.2 BACT FOR THE 

### C FB B OILERS


### 5.2.1 Step 1: Identify All Available Control Technologies
5.2.1.1 Inherently Lower

- Emitting Processes/Practices/Designs A summary of available, lower greenhouse ga s emitting processes, practices, and designs for CFB boilers is presented below. However, EPA must also be mindful of the fact that the State of Texas has issued a PSD permit for LBEC that contemplates CFB technology.



### 5.2.1.1.1

Las Bri sas will consist of four steam

- electric generating units and related support facilities. The highly

- efficient LBEC steam

- electric generating units will burn 100% petroleum coke, a product of nearby refineries

. One measure of a steam

- electric generating u nit’s efficiency is its “heat rate,” which is expressed as the numb er of British thermal units (Btu) needed to produce a kilowatt

- hour or kWh of energy. The lower a unit’s heat rate the more efficient it is. Las Brisas’ guaranteed full load net plant hea t rate will be 9,275 Btu/kWh. For 2009, the average operating heat rate for petroleum

- fired (includes petroleum coke

- fired) steam

- electric generating units in the United States was 11,002 Btu/kWh. See U.S. Energy Information Administration, Electric Powe r Annual 2009 at 49, Table 5.3, available at 

### CFB Boiler Energy Efficiency

http://www.eia.doe.gov/cneaf/electricity/epa/ epa_sum.html.

CO 2 is a product of combustion of fuel containing carbon, which is inherent in any power generation technology using fossil fuel. It is not possible to reduce the amount of CO 2 generated from combustion, as CO 2 is the essential product of the chemical reaction between the fuel and the oxygen in which it burns, not a b yproduct caused by imperfect combustion. As such, there is no technology available that can effectively reduce CO 2 generation by adjusting the conditions in which combustion takes place

. The only effective means to reduce the amount of CO 2 generated by a fuel

- burning power plant is to generate as much electric power as possible from the combustion, thereby reducing the amount of fuel needed to meet the plant’s required power output. This result is obtained by using the most efficient generating technol ogies, so that as much of the energy content of the fuel as possible goes into generating power.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

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010303 40 Steam Generator Design The steam generators (boilers) proposed for Las Brisas plant are heat exchangers designed to capture as much thermal energy as possible from the combustion process. This is accomplished through heat recovery at a high pressure level utilizing an economizer, evaporator section, and superheater sections. Furt hermore, thermal energy will be recovered in steam reheaters to improve thermal cycle efficiency. These heat transfer sections will be made up of many thin

- walled tubes to provide surface area to maximize the transfer of heat to the working fluid. Many of the tubes in the convective backpass of the boiler will also include extended surfaces (e.g., fins). The extended surface optimizes the heat transfer, while minimizing the overall size of the steam generator.

Feed Water Heaters and Economizer Feedwater heaters improve cycle efficiency through extracting steam from the steam turbine flow path and utilizing that steam to preheat feedwater to the steam generator via multiple increments of heating. In this manner, the thermodynamic efficiency of t he system is improved by reducing the irreversibilities involved with steam generation. This is traditionally called regenerative feedwater heating where the steam is partially expanded through the steam turbine to produce useful electric generation and t hen extracted at multiple pressure levels such that the remaining energy in the steam is recovered within the thermal cycle rather than exhausted to the condenser. The LBEC feedwater system will be designed with 7 stages of regenerative heaters. The infl uence of feedwater heating on overall thermal cycle efficiency for a cycle with 7 stages of feedwater heating as compared to a thermal cycle with a single feedwater heater can be estimated as an approximate improvement of 1.5 to 1.75 percent in higher heat ing value, net plant efficiency. This is generally equivalent to an improvement in net plant heat rate and resultant reduction in fuel consumption of approximately 4.4 percent. Fluidized Stripper
- Coolers The spent bottom ash from the boiler furnace will be cooled in a fluidized stripper

- cooler. Water from the condenser will be used to cool the ash to a temperature at which conventional ash disposal equipment can be utilized. This water recovers heat from the bottom ash and returns it to the feed water s ystem thus adding another element of efficiency to the overall system.

Boiler Feed Water Pump s Large pumps are used to deliver the pre

- heated water to the boiler. These pumps can be driven by electric motor or by a dedicated steam turbine driver. Steam turbine drivers convert thermal energy extracted from the steam turbine cycle directly to the mechanical pumping energy required and are not a parasitic electrical load in the system. E lectric drives require additional energy conversion processes (thermal to mechanical, mechanical to electrical, and electrical back to mechanical) , with their associated conversion inefficiencies to achieve the same pumping capacity. Where steam is available, using a steam turbine drive eliminates the inherent losses in the energy conversion process from mechanical to electrical and electrical back to mechanical. To best optimize system efficiencies, the steam exhaust from the steam turbine drive will be recovered and returned to the feed water system through the deaerator to increase the temperature of the feed water entering the boiler. Las Brisas will be equipped with steam turbine drivers for the boiler feed water pumps.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 41 Regenerative Air Heater s Similar to the boiler feed water, air that enters the boiler combustion system at a higher temperature than the ambient air will increase the efficiency of the system. Each boiler will be equipped with a regenerative air heater that will recov er some of the boiler flue gas exhaust energy to “pre

- heat” the air introduced into the combustion system.

Insulation Boilers are designed to maximize the conversion of the thermal combustion energy to steam. One aspect of the boiler design in maximizi ng this heat conversion is the use of refractory lining systems and mineral fiber insulation. Insulation minimizes heat loss to the surroundings, thereby improving the overall efficiency of the boiler and steam cycle . Insulation will be applied to the pa nels that make up the shell of the boilers and associated convecti ve heat exchange surfaces . The insulation will also be applied to the exhaust gas air ducts , CFB cyclones, and plenums as wells all the high

- temperature steam and water lines throughout the facility

. Minimizing Fouling of Heat Exchange Surfaces The boilers will be made up of a number of tubes within the shell of the unit that are used to generate steam from the combustion process . To maximize this heat transfer, the tubes and their extended surfaces will be kept as clean as possible since f ouling of the tube surfaces impedes the transfer of heat. Fouling occurs from the solid ash constituents within the exhaust gas stream. To minimize fouling, steam soot blowers will be utilized to periodically remove deposits from the heat transfer surfaces. Water wash manifolds will also be provided in the regenerative air heater. Additionally, periodic cleaning of the tubes during outages will be performed. By reducing fouling, the thermal efficiency of the unit will be maintained. Minimizing Vented Steam and Repair of Steam Leaks Las Brisas will minimize steam vents and will promptly repair steam leaks to maintain t he plant ’s efficiency

. The facility has very few locations where steam will be vented from the system, including at the deaerator vents , blowdown tank vents, and vacuum pumps/steam jet air ejectors. These vents are necessary to improve the overall heat transfer within the b oiler and condenser by removing solids , contaminants, and air that potentially blankets the heat transfer surfaces resulting in reduced equipment performance. Steam Turbine Design The steam turbine for this project will be a modern, high

- efficiency, reheat, multiple extraction, condensing unit. The overall efficiency of the steam turbine has been maximized by proper design of a number of items, including the inlet steam conditions , extractions for regenerative feed water heating, reheat steam conditions, the exhaust steam conditions, blade design, last stage blading selection, the turbine seals, and the generator efficiency. Use of Reheat Cycles The efficiency of a steam turbine is directly related to the steam conditions entering the turbine. The higher the steam temperature and pressure, the higher the overall efficiency. Furthermore,P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 42 to achieve increased thermal cycle efficiencies, a reheat cycle is employed at Las Brisas. T his is implemented to increase the amount of recoverable energy within the expansion path of the steam turbine while maintaining an acceptable moisture content in the exhaust steam. If the moisture content of the exhaust steam is too high, erosion of the last

- stage turbine blades occurs. This cycle reheats partially expanded steam from the steam turbine to increase unit efficiency

. . Use of Exhaust Steam Condenser Steam turbine efficiency is also improved by lowering the exhaust steam pressure of the unit. Generally, t he lower the exhaust pressure, the higher the overall turbine efficiency. For high

efficiency units, such as Las Brisas , the exhaust steam is wet or saturated under vacuum conditions. This is accomplished by the use of a condens er with vacuum pumps or air ejectors

. The condenser is typically a shell and tube heat exchanger with cooling water flowing through the tubes and the turbine exhaust steam condensing in the shell. The condensing steam creates a vacuum in the condenser, w hich allows the steam to expand to a lower pressure, increasing the amount of recoverable energy and power generation and thus increasing the steam turbine efficiency. This vacuum is dependent on the temperature of the cooling water. As the temperature o f the cooling water is lowered, the absolute vacuum attainable is lowered and the steam turbine cycle is more efficient. Efficient Generator Design The generator is also a key element in the overall performance of the unit . The modern generator is a high

- efficiency unit. The generator for modern steam turbines is typically cooled by one of three methods. These methods are open

- air cooling, totally enclosed water to air cooling, or hydrogen cooling. Of the three methods, water and hydrogen cooling are t he most efficient due to the unit’s ability to maintain lower coil temperatures and resulting in fewer stray losses in the generator. The steam turbine generator for this project will have water cooled stator windings and will have a hydrogen

- cooled rotor

.


### 5.2.1.1.2 The EPA provided the following guidance regarding the use of lower GHG emitting fuel as a BACT consideration: 

### Use of Lower GHG Emitting Fuel

Thus, clean fuels which would reduce GHG emissions should be considered, but EPA has recognized that the initial list of control options for a BACT analysis does not need to include “clean fuel” options that would fundamentally redefine the source. Such options include those that would require a permit applicant to switch to a primary fuel type ( i.e., coal, n atural gas, or biomass) other than the type of fuel that an applicant proposes to use for its primary combustion process. For example, when an applicant proposes to construct a coal

- fired steam electric generating unit, EPA continues to believe that permi tting authorities can show in most cases that the option of using natural gas as a primary fuel would fundamentally redefine a coal

- fired electric generating unit. Furthermore, when a permit applicant has incorporated a particular fuel into one aspect of the project design (such as startup or auxiliary applications), this suggests that a fuel is “available” to a permit applicant. In such circumstances, greater utilization of a fuel that the applicant is already proposing to use in some aspect of the projec t designP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 43 should be listed as an option in Step 1 unless it can be demonstrated that such an option would disrupt the applicant’s basic business purpose for the proposed facility. 27 It is unquestionable that petroleum coke will continue to be generated as part of the petroleum refining process, with approximately 1.7 million tons per year produced in Corpus Christi and approximately 35 million tons produced throughout other parts of the Gulf Coast region. Presently, the majority of Gulf Coast petroleum cok e is transported to remote international markets where it is burned in cement kilns, power plants, and other processes. Because this petroleum coke will continue to be generated, shipped abroad, and burned in these processes in the absence of a local cons umer, the LBEC is expected to result in a net decrease in global GHG (and other) emissions, as it will (1) eliminate the GHG emissions associated with the transportation of locally produced petroleum coke to international markets, and (2) reduce the amount of GHG emissions generated from burning the petroleum coke for energy recovery because the LBEC boilers and turbines are more efficient than the existing processes currently combusting the petroleum coke. Natural gas will be utilized during startups to i nitiate the combustion process and to heat the boiler and fuel bed to a level where the petroleum coke combustion will be self

- sustaining and stable. At that point, which will be typically 40% to 50% capacity, the gas system will be turned off. The CFB b oilers are not designed to be fired 100% with natural gas. The use of natural gas as a primary fuel is contradictory to the fundamental elements of LBEC’s business plan.



### 5. 2 .1.2 Add

- On Controls

In addition to the power generation process technology optio ns discussed above, it is appropriate to consider add

- on technologies as possible ways to capture GHG emissions that are emitted from petroleum coke combustion in the proposed project’s CFB boilers and to prevent them from entering the atmosphere. These e merging carbon capture and storage (CCS) technologies generally consist of processes that concentrate CO 2 from combustion process flue gas , and then inject it into geologic formations such as oil and gas reservoirs, unmineable coal seams, and underground s aline formations

. E merging CO 2 capture technologies that have been identified as potentially applicable to CFB boiler operation include post

- combustion chemical absorption and oxy

- combustion

. Post

- combustion chemical absorption processes have focused primarily on the use of amines and chilled ammonia as solvents. In contrast, oxy

- combustion is a process that burns fuel with a highly concentrated oxygen stream in order to increase the outlet concentration of CO 2 , thereby reducing the need for a post

- co mbustion CO 2 concentration step.
Amine absorption has been commercially applied to processes in the petroleum refining and natural gas processing industries and to exhausts from gas

- fired industrial boilers, but is only currently being applied to solid fu el

- fired power plant boilers on a research and development basis

. The U.S. Department of Energy’s National Energy Technology Laboratory ( DOE

- NETL) provides the following brief description of the current status of chemical

- based post

- combustion CO 2 capture technology and related costs:

27 EPA, PSD and Title V Permitting Guidance For Greenhouse Gases , March 2011, at 48

- 49.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 44 “...Absorption processes based on chemical solvents such as amines have been developed and deployed commercially in certain industries. To date, however, their use in pulverized coal (PC) power plants has been restricted to sl ipstream applications, and no definitive analysis exists as to the actual costs for a full

- scale capture plant. Preliminary analysis conducted a t NETL indicates that CO 2 capture via amine scrubbing and compression to 2,200 psia could raise the cost of electricity from a new supercritical PC power plant by 65 percent, from 5.0 cents per kilowatt

- hour to 8.25 cents per kilowatt

- hour...” 28

The DOE

- NETL adds:

“... Separating CO 2 from this flue gas stream is challenging for several reasons:

**•** CO 2 is present at dilute concentrations (13

- 15 volume percent in coal

fired systems 29

**•** Trace impurities (particulate matter, sulfur dioxide, nitrogen oxides) in the flue gas can degrade sorbents and reduce the effectiveness of certain CO 2 capture processes. and 3

- 4 volume percent in gas

- fired turbines) and at low pressure (15

- 25 pounds per square inch absolute [psia]), which dictates that a high volume of gas be treated.

**•** Compressing captured or separated CO 2 from atmospheric pressure to pipeline pressure (abou t 2,000 psia) represents a large auxiliary power load on the overall power plant system ...” 30

If CO 2 capture could be achieved at a power plant, it would need to be routed to a geologic formation capable of long

- term storage. The long

- term storage potential for a formation is a function of the volumetric capacity of a geologic formation and CO 2 trapping mechanisms within the formation, including dissolution in brine , react ions with minerals to form solid carbonates , and/or adsorption in porous rock. The DOE

- NETL describes the geologic formations that could potentially serve as CO 2 storage sites as follows:

“ Geologic carbon dioxide (CO 2 ) storage involves the injection of supercritical CO 2 into deep geologic formations (injection zones) overlain by compete nt sealing formations and

28 DOE

- NETL, Carbon Sequestration: FAQ Information Portal ,

http://extsearch1.netl.doe.gov/search?q=cache:e0yvzjAh22cJ:www.netl.doe.gov/technologies/carbon_seq/FAQs/te ch

- status.html+emerging+R%26D&access=p&output=xml_no_dtd&ie=UTF

8&client=default_frontend&site=default_collection&proxystylesheet=default_fronte nd&oe=ISO

- 8859

- 1 (last visited Sept. 28, 2011).

29 CO 2 concentrations in exhausts from the project’s petroleum coke

- fired boilers will be similar to coal

- fired boilers.

30 DOE

- NETL, Carbon Sequestration: FAQ Information Portal ,

http://extsearch1.netl.doe.gov/search?q=cache:e0yvzjAh22cJ:www.netl.doe.gov/technologies/carbon_seq/FAQs/te ch

- status.html+emerging+R%26D&access=p&output=xml_no_dtd&ie=UTF

8&client=default_frontend&site=default_collection&proxystyles heet=default_frontend&oe=ISO

- 8859

- 1 (last visited Sept. 28, 2011).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 45 geologic traps that will prevent the CO 2 from escaping. Current research and field studies are focused on developing better understanding of 11 major types of geologic storage reservoir classes , e ach having their own unique opportunities and challenges. Understanding these different storage classes provides insight into how the systems influence fluids flow wit hin these systems today, and how CO 2 in geologic storage would be anticipated to flow in the future. The different storage formation classes include: deltaic, coal/shale, fluvial, alluvial, strandplain, turbidite, eolian, lacustrine, clastic shelf, carbon ate shallow shelf, and reef. Basaltic interflow zones are also being considered as potential reservoirs. These storage reservoirs contain fluids that may include natural gas, oil, or saline water; any of which may impact CO 2 storage differently...” 31



### 5.2.2 Step 2: Eliminate Technically Infeasible Options
In this section, Las Brisas addresses the potential feasibility of implementing CCS technology as BACT for GHG emissions from the proposed project’s petroleum coke

- fired fluidized bed boilers . Each component of CCS technology ( i.e., capture and compression, transport, and storage ) is discussed separately.



### 5.2.2.1 CO 2 

### Capture , Compression , and Transport Though amine absorption technology for CO 2 capture has been utilized in the petroleum refining and natural gas process ing industries in high pressure, pre

- combusion applications and to exhausts from small

- scale gas - fired industrial boilers in post combustion application , it is not yet commercially available for post

- combustion application in large scale solid fuel

- fired b oilers used for power generation , which have considerably larger flow volumes and considerably lower CO 2 concentrations than other processes . The Obama Administration’s Interagency Task Force on Carbon Capture and Storage confirms this in its recently com pleted report on the current status of development of CCS systems: “Current technologies could be used to capture CO 2 from new and existing fossil energy power plants; however, they are not ready for widespread implementation primarily because they have not been demonstrated at the scale necessary to establish confidence for power plant application. Since the CO 2 captur e capacities used in current industrial processes are generally much smaller than the capacity required for the purposes of GHG emissions mitigation at a typical power plant, there is considerable uncertainty associated with capacities at volumes necessary for commercial deployment.” 32

31 DOE

- NETL, **Carbon Sequestration:** Geologic Storage Focus Area ,

http://www.netl.doe.gov/technologies/carbon _seq/corerd/storage.html (last visited Sept. 28, 2011)
32 Report of the Interagency Task Force on Carbon Capture and Storage at 50 ( Aug

. 2010 ).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 46 In its current CCS research program plans, the DOE

- NETL confirms that commercial CO 2 capture technology for large

- scale power plant boilers is not yet available and suggests that it may not be available until at least 2020:

“ The overall objective of the Carbon Sequestration Program is to develop and advance CCS technologies that will be ready for widespread commercial deployment by 2020. To accomplish widespread deployment, four program goals have been established: (1) D evelop technologies that can separate, capture, transport, and store CO 2 using either direct or indirect systems that result in a less than 10 percent increase in the cost of energy by 2015; (2) D evelop technologies that will support industries’ ability t o predict CO 2 storage capacity in geologic formations to within ±30 percent by 2015; (3) D evelop technologies to demonstrate that 99 percent of injected CO 2 remains in the injection zones by 2015; (4) C omplete Best Practices Manuals (BPMs) for site selection, characterization, site operations, and closure practices by 2020. Only by accomplishing these goals will CCS technologies be ready for safe, effective commercial deployment both domestically and abroad beginning in 2020 and through the next seve ral decades.” 33 To corroborate that commercial availability of CO 2 capture technology for large

- scale power plant projects will not occur for several more years, Alstom, one of the major developers of commercial CO 2 capture technology using post

- combustion amine absorption, post

- combustion chilled ammonia absorption, and oxy

- combustion, states on its web site that its CO 2 capture technology will become commercially available in 2015. 34 However, it should be noted that in committing to this timeframe, the company does not indicate whether such technology will be able to handle the volume of CO 2 emissions generated by a project of the size of Las Brisas

. The “large

- scale demonstration p roject” to which Alstom refers on its web site would be able to capture 1 million tons of CO 2 per year , an order of magnitude less than the CO 2 generated by the Las Brisas project

. Even if it is assumed that CO 2 capture and compression could feasibly be a chieved for the proposed project, the high

- volume CO 2 stream generated would need to be transported to a facility capable of storing it. P otential geologic storage sites in Texas , Louisiana, and Mississippi to which CO 2 could be transported if a pipeline was constructed are delineated on the map found at the end of Section 5. 35

33 DOE

- NETL, Carbon Sequestration Program: Technical Program Plan, at 10 (Feb. 2011). The potential length of such a CO 2 transport pipeline is uncertain due to the uncertainty of identifying a site(s) that is suitable for large

- scale, long

- term CO 2 storage.

34 Alstom, Alstom’s Carbon Capture Technology Commercially “Ready to Go” by 2015 , Nov.30, 2010,

http://www.alstom.com/australia/news

- and

- events/pr/ccs2015/ (last visited Sept.28, 2011).

35 Susan Hovorka , University of Texas at Austin, Bureau of Economic Geology, Gulf Coast Carbon Center, New

Developments: Solved and Unsolved Questions Regarding Geologic Sequestration of CO 2 as a Greenhouse Gas Reduction Method (GCCC Digital Publication #08

- 13) at slide 4 (Apr. 2008), available at : http://www.beg.utexas.edu/gccc/forum/codexdownloadpdf.php?ID=100 (last visited Sept.28, 2011).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 47 T he closest site that is currently being field

- tested to demonstrate its capacity for large

- scale geological storage of CO 2 is the Southwest Regional Partnership on Carbon Sequestration’s (SWP) SACROC test site, which is located in Scurry County, Texas approxi mately 395 miles away (see the map at the end of Section 5 for the test site location). Therefore, to access this potentially large

- scale storage capacity site, assuming that it is eventually demonstrated to indefinitely store a substantial portion of the large volume of CO 2 generated by the proposed project, a very long and sizable pipeline would need to be constructed to transport the large volume of high

- pressure CO 2 from the plant to the storage facility, thereby rendering implementation of a CO 2 trans port system infeasible.



### 5.2.2.2 CO 2 

### Storage

Even if it is assumed that CO 2 capture and compression could feasibly be achieved for the proposed project and that the CO 2 could be transported economically, the feasibility of CCS technology would still depend on the availability of a suitable sequestration site. The suitability of potential storage sites is a function of volumetric capacity of their geologic formation s , CO 2 trapping mechanisms within formations ( including dissolution in brin e, reactions with minerals to form solid carbonates, and/or adsorption in porous rock ), and potential environmental impacts resulting from injection of CO 2 into the formations. P otential environmental impacts resulting from CO 2 injection that still require assessment before CCS technology can be considered feasible include:

**•** Uncertainty concerning the significance of dissolution of CO 2 into brine,

**•** Risks of brine displacement resulting from large

- scale CO 2 injection, including a pressure leakage risk for brine into underground drinking water sources and/or surface water,

**•** Risks to fresh water as a result of leakage of CO 2 , including the possibility for damage to the biosphere, underground drinking water sources, and/or surface water, 36

**•** Potential effe cts on wildlife. and

Potential ly suitable storage sites, including EOR sites and saline formations , exist in Texas , Louisiana, and Mississippi. In fact, site s with such recognized potential for some geological storage of CO 2 are located within 5 miles of the proposed project , but such nearby sites have not yet been technically demonstrated with respect to all of the suitability factors described above. In comparison, t he closest site that is currently being field

- tested to demonstrate its capacity for geolog ical storage of the volume of CO 2 that would be generated by the proposed power unit, i.e., SWP’s SACROC test site is located in Scurry County, Texas approximately 395 miles away

. It should be noted that, based on the suitability factors described above, currently the suitability of the SACROC site or any other test site to store a substantial portion of the large volume of CO 2 generated by the proposed project has yet to be fully demonstrated

.

36 Id.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 48 Based on the reasons provided above, LBEC believes that CCS technology should be eliminated from further consideration as a potential feasible control technology for purposes of this BACT analysis. 

### 5.2.3 Step 3: Rank Remaining Control Technologies
As documented above, implementation of CCS technology is currently in feasible , leaving energy efficiency measures as the only technically feasible emission control options

. As all of the energy efficiency related processes, practices, and designs discussed in Section 5 .1.1 of this application are being proposed for this project, a ranking of the control technologies is not necessary for this application.



### 5.2.4 Step 4: Evaluate Most Effective Controls and Document Results

As all of the energy efficiency related processes, practices, and designs discussed in Section 5 .1.1 of this application are being proposed for this project, an examination of the energy, environmental, and economic impacts of the efficiency designs is not necessary for this application. Because the CCS add

- on control option discussed in Section 5.1 .2 was determined to be technically infeasible, an examination of the energy, environmental, and economic impacts o f that option is not necessary for this application. 

### 5.2.5 Step 5: Select BACT

Las Brisas propose s as BACT for this project, to utilize energy e fficient equipment in the plant design and follow the manufacturer’s recommended operating and maintenance procedures. To determine the appropriate output

- based GHG BACT limit , Las Brisas started with the CFB’s d esign net h eat r ate and then calculated a c ompliance margin based upon reasonable degradation factors that may foreseeably reduce efficiency under real

- world conditions. The guaranteed design heat rate for the CFB boilers is as follows:

Las Brisas CFB Boiler Design Net Heat Rate

Base Load 90% Boi ler Continuous Steam Rating 75% Boiler Continuous Steam Rating
9,137 Btu/kWhr 9,247 Btu/kWhr 9,433 Btu/kWhr

Note that this rate reflects the facility’s “net” power production, meaning the denominator is the amount of power provided to the grid; it does not reflect the total amount of energy produced by the plant, which also includes auxiliary load consumed by operation of the plant. To determine an appropriate net output based BACT limit for the permit, the following compliance margins are added to the base heat rate limit :P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 49 **•** A 5 % de sign margin reflecting the CFB boiler provider’s performance guarantee

**•** A 6% performance margin reflecting CFB boiler efficiency degradation over a 25

- year peri od

**•** A 3% performance margin reflecting degradation of auxiliary plant equipment due to use over time and variability in CFB boiler efficiency due to petroleum coke fuel variability
To account for reduced load operation over the course of a year, Las Brisas is proposing a net, output based BACT emission rate of 1.2 8 ton CO 2 e/MW

- hr (2.5 5 lb CO 2 e/kW

- hr) on a 12

- month rolling average, which is derived from the design net heat rate at 75% boiler continuous steam rating, and adding the above compliance margins. C alculation of the net heat rate and the equivalent ton CO 2 e/MWhr are provided on Table 5

- 1 of this application.

Las Brisas performed a search of the EPA’s RACT/BACT/LAER Clearinghouse for solid

- fuel

fired electric generating units and found no entries which address BACT for GHG emissions. Although not listed in the RACT/BACT/LAER Clearinghouse, a GHG BACT analysis was performed by the Wolverine Power Supply Cooperative for a solid

- fuel

- fired power plant. A discussion of Las Brisa s’ proposed BACT as compared to the Wolverine project is provided below: The Wolverine Power Supply Cooperative air permit application proposed the construction of two, 3,030 MMBtu/hr, circulating fluidized bed boilers firing coal, petroleum coke, and bio mass to be located in Rogers City, Michig a n. The Permit to Construct, issued on July 29, 2011 listed a GHG BACT limit of 2.1 lb CO 2 e/kW

- hr, gross output, 12

- month rolling average. Note that the BACT limit is based on gross electrical output and not net e lectrical output. This limit was calculated assuming that a CFB boiler was operating at base load of 660 MW (gross) for 8,760 hours per year. The BACT limit did not account for reduced efficiencies at lower operating loads. The Wolverine BACT limit was also based on a CO 2 emission factor for a subbituminous coal/petroleum coke/bio

- mass mixture of 221.5 lb CO 2 /MMBtu versus the emission factor for 100% petroleum coke combustion of 225.0 lb CO 2 /MMBtu. For direct comparison purposes, the “design” net heat r ate for each CFB boiler represented in the Wolverine application was 9,180 Btu/kW

- hr (net) compared to Las Brisas’ “design” net heat rate of 9,137 Btu/kW

- hr (net), making Las Brisas’ CFB boilers slightly more efficient than the Wolverine CFB boilers on a “ design” net electrical output basis.



### 5.3 BACT FOR 

### SF 6 

### I NSULATED 

### E LECTRICAL 

### E QUIP MENT


### 5.3.1 Step 1: Identify All Available Control Technologies Step 1 of the Top

- Down BACT analysis is to identify all feasible control technologies. The predominate technology used is state

- of

- the

- art SF 6 technology with leak detection to limit fugitive emissions. In comparison to older SF 6 circuit breakers, modern breakers are designed as a totally enclosed

- pressure system with far lower potential for SF 6 emissions. In addition, th e effectiveness of leak

- tight closed systems can be enhanced by equipping them with a densityP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 50 alarm that provides a warning when 10% of the SF 6 (by weight) has escaped. The use of an alarm identifies potential leak problems before the bulk of the SF 6 has e scaped, so that it can be addressed proactively in order to prevent further release of the gas. One alternative considered in this analysis is to substitute another, non

- greenhouse

- gas substance for SF 6 as the dielectric material in the breakers. Potenti al alternatives to SF 6 were addressed in the National Institute of Standards and Technology (NTIS) Technical Note 1425, Gases for Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure SF 6

. 37



### 5.3.2 Step 2: Eliminate Technically Infeasible Options According to the report NTIS Technical Note 1425, SF 6 is a superior dielectric gas for nearly all high voltage applications

. 38 It is easy to use, exhibits exceptional insulation and arc

- interruption properties, and has proven its performance by many years of use and investigation. It is clearly superior in performance to the air and oil insulated equipment used prior to the development of SF 6 - insulated equipment. The report concluded that although “...various gas mixtures show considerable promise for use in new equipment, particularly if the equipment is designed specifically for use with a gas mixture... it is clear that a significant amount of research must be performed for any new gas or gas mixture to be used in electrical e quipment.” Therefore there are currently no technically feasible options besides use of SF 6 .


### 5.3.3 Step 3: Rank Remaining Control Technologies

The use of state

- of

- the

- art SF 6 technology with leak detection to limit fugitive emissions is the highest ranked con trol technology that is technically feasible for this application.



### 5.3.4 Step 4: Evaluate Most Effective Controls and Document Results

E nergy, environmental, or economic impacts were not addressed in this analysis because the use of alternative , non - greenhouse

- gas substance for SF 6 as the dielectric material in the breakers is not technically feasible

.


### 5.3.5 Step 5: Select BACT Based on this top

- down analysis, Las Brisas concludes that using state

- of

- the

- art enclosed

pressure SF 6 circuit breakers with leak detection would be the BACT control technology option. The circuit breakers will be designed to meet the latest of the American National Standards

37 Christophorous, L.G., J.K. Olthoff, and D.S. Green, Gases for Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure SF 6, NIST Technical Note 1425, Nov.1997.
38 Id. at 28

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010303 51 Institute ( ANSI ) C37.013 standard for high voltage circuit breakers

. 39 The propos ed circuit breaker at the generator output will have a low pressure alarm and a low pressure lockout. This alarm will function as an early leak detector that will bring potential fugitive SF 6 emissions problems to light before a substantial portion of the SF 6 escapes. T he lockout prevents any operation of the breaker due to lack of “quenching and cooling” SF 6 gas.
Las Brisas will monitor emissions annually in accordance with the requirements of the Mandatory Greenhouse Gas Reporting rules for Electrical Transmission and Distribution Equipment Use

. 40 Annual SF 6 emissions will be calculated according to the mass balance approach in Equation DD

- 1 of Subpart DD.



### 5.4 BACT FOR 

### A UXILIARY 

### B OILERS AND 

### P R OP ANE 

### V APORIZERS Two nominally rated 180 MMBtu/hr auxiliary boilers (EPNs AUX

- BOIL1 and AUX

- BOILL2) will be utilized during start

- up and shutdown activities to provide auxiliary steam which may be required to stabilize the system. Each auxiliary boiler wi ll be limited to 2,500 hours of operation per year. Two nominally rated 16 MMBtu/hr propane vaporizers (EPNs: PROP

- VAP1 and PROP

- VAP2) will be utilized as a source of CFB start

- up fuel in the event natural gas is not available. Each vaporizer will be l imited to 2,500 hours of operation per year. The combined calculated GHG emissions from the two auxiliary boilers and the two propane vaporizers represent less than 0.5% of the total proposed GHG emissions from the site. LBEC propose s as BACT for this pr oject, to follow manufacturer’s recommended operating and maintenance procedures

. Among other recently issued or currently pending GHG permits, the Wolverine Power Supply Cooperative permit and the Palmdale Hybrid Power Project permit included BACT determ inations for limited use, auxiliary boilers and heaters

. The Wolverine Permit included a 72.4 MMBtu/hr diesel

- fired auxiliary boiler, limited to 4,000 hours operation per year. The Permit listed BACT for GHG for the auxiliary boiler to incorporate energy efficient equipment wherever practical in the design of the auxiliary boiler. The Wolverine Permit did not include an output based BACT limit for the auxiliary boiler.
The application for the Palmdale Hybrid Power Project (PHPP) was submitted in May 201 1 and a draft permit was issued by the Antelope Valley Air Quality Management District in August 2011. The PHPP application proposed the construction of a power plant utilizing natural

- gas fired combustion turbine combined cycle generators located in Palmdale, California. The project also included a 110 MMBtu/hr natural

- gas - fired auxiliary boiler, limited to 500 hours per year operation, and a 40 MMBtu/hr natural

- gas - fired heater, limited to 1,000 hours per year

39 ANSI Standard C37.013, Standard for AC High

- Voltage Generator Circuit Breakers on a Symmetrical Current

. 40 See 40 C.F.R. Pt. 98, Subpt. DD.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

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010303 52 operation. The Palmdale Permit listed BACT for GHG for the auxiliary boiler and heater as annual tune

- ups. The Palmdale Permit did not include an output based BACT limit for the auxiliary boiler or heater.



### 5.5 BACT FOR 

### E MERGENCY 

### E NGINES The proposed project will include installation of high effi ciency diesel

- fired emergency generators, fire water pump engine s, and emergency boiler feed water pump engines. The use of diesel is being used as fuel for the emergency engines in the event of unavailability of a natural gas supply. Use of these engine s for purpose of m aintenance checks and readiness testing will be limited to 1 00 hours per year each . The new engines will be subject to the New Source Performance Standard for Stationary Compression Ignition Internal Combustion Engines

. 41 As such, the en gines will be required to meet specific emission standards based on engine size, model year, and end use. The use of engines with a low annual capacity factor and following manufacturer’s recommended operating and maintenance procedures is proposed as BAC T for GHG emissions.

41 See 40 C.F.R. Pt. 60, Subpt. IIII.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

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010303 53 

## M AP OF 

## E XISTING 

## CO 2 

## P IPELINES AND 

## P OTENTIAL 

## G EOLOGIC 

## S TORAGE 

## S ITES IN 

## T EXAS

### Pipelines for 

### naturally occuring CO ,

NEW MEXICO



# SACROC Southwest Partnership NM Tech

u
- , uO 200 

## miles 

# r- -,-'-r' ---,- ' -,---'r---,-'' r Ii, i I 

# o 300 

## kilomete rs

Source: Base drawing from Uni v ersity of Texas at Austin Bureau of Economic Geology, Gulf Coast Carbon Center.' 

## Oligocene o 

# TEXAS

Austin ' 0

### ou~~ 

# Frio Test Site SECARB Phase 11&111 Cranfield

ALABAMA

o 

## C02-EOR candidate reservoirs

- Existing C02 pipelines Additional oil-production area with CO 2 -EOR production and potential 

# o Major oil playsBase Load 90% Load 75% Load Design Net Heat Rate 9,137 9247 9433 Btu/kWh (HHV) 5% 5% 3% Manufacturer's Guarantee Design Margin 6% 6% 6% Degradation Margin for CFB Boilers 3% 3% 3% Margin for Degradation of Auxiliary Equipment and Fuel Variability 10,474.6 10,600.7 10,607.9 Btu/kWH (HHV)

Calculate of Annual Average ton CO2e/MWh Limit for each CFB
Annual Average Heat Rate Heat Input Required to Produce 1 MW Pollutant Emission Factor GHG Mass Emissions Global Warming Potential 2 CO 2 e
Btu/kW-hr (HHV, Net) (MMBtu/yr) (kg/MMBtu) 1 (ton/MWhr) (ton/MWhr)

10,607.9 10.61 Limestone calcination CO 2 6.69 0.078 1 0.07821

Pet Coke combustion CO 2 102.0400 1.193 1 1.19316
Pet Coke combustion CH 4 0.0110 0.00006 21 0.00123
Pet Coke combustion N 2 O 0.0016 0.00001 310 0.00263

Totals 1.27 1.28 2.55 lb CO2e/kW-hr Note 1. Petroleum Coke combustion factors from Table C-1 and C-2 of 40 CFR Part 98 CO 2 emission factor for limestone calcination calculated on Table 3-1 2. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Table 5-1 Calculation of Output Based BACT Limit Las Brisas Energy Center LLC

Calculated Net Heat Rate with Compliance Margins

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010303 56 

## 6.0 O THER 

## PSD R EQUIREMENTS



### 6.1 I MPACTS 

### A NALYSIS An impacts analysis is not being provided with this application in accordance with EPA’s recommendations: Since there are no NAAQS or PSD increments for GHGs, the requirements in sections 52.21(k) and 51.166(k) of EPA’s regulations to demonstrate that a source does not cause contribute to a violation of the NAAQS are not applicable to GHGs. Therefore, there is no requirement to conduct dispersion modeling or ambient monitoring for CO 2 or GHGs. 42 An impacts analysis for non

- GHG emissions was submitted w ith the application for TCEQ Permit No. 85013/ PSD

- TX

- 1138/HAP

- 48.



### 6.2 GHG P RECONSTRUCTION 

### M ONITORING A pre

- construction monitoring analysis for GHG is not being provided with this application in accordance with EPA’s recommendations : EPA does not consider it necessary for applicants to gather monitoring data to assess ambient air quality for GHGs under section 52.21(m)(1)(ii), section 51.166(m)(1)(ii), or similar provisions that may be contained in state rules based on EPA’s rules. GHGs do not affect “ambient air quality” in the sense that EPA intended when these parts of EPA’s rules were initially drafted. Considering the nature of GHG emissions and their global impacts, EPA does not believe it is practical or appropriate to expect permitting authorities to collect monitoring data for purpose of assessing ambient air impacts of GHGs. 43



### 6.3 A DDITIONAL 

### I MP ACTS 

### A NALYSIS A PSD additional impacts analysis is not being provided with this application in accordance with EPA’s recommendations : Furthermore, consistent with EPA’s statement in the Tailoring Rule, EPA believes it is not necessary for applicants or permitting authorities to assess impacts from GHGs in the context of the additional impacts analysis or Class I area provisions of the PS D regulations for the following policy reasons. Although it is clear that GHG emissions contribute to global warming and other climate changes that result in impacts on the environment, including impacts on Class I areas and soils and vegetation due to th e global scope of the problem, climate change modeling and evaluations of risks and

42 EPA, PSD and Title V Permitting Guidance For Greenhouse Gases at 48

- 49.

43 Id. at 49.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

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010303 57 impacts of GHG emissions is typically conducted for changes in emissions orders of magnitude larger than the emissions from individual projects that might be analyzed in PS D permit reviews. Quantifying the exact impacts attributable to a specific GHG source obtaining a permit in specific places and points would not be possible with current climate change modeling. Given these considerations, GHG emissions would serve as th e more appropriate and credible proxy for assessing the impact of a given facility. Thus, EPA believes that the most practical way to address the considerations reflected in the Class I area and additional impacts analysis is to focus on reducing GHG emis sions to the maximum extent. In light of these analytical challenges, compliance with the BACT analysis is the best technique that can be employed at present to satisfy the additional impacts analysis and Class I area requirements of the rules related to G HGs. 44 An additional mpacts analysis for non

- GHG emissions was submitted with the application for TCEQ Permit No. 85013/ PSD

- TX

- 1138/HAP

- 48.

44 Id.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

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010303 58 

## 7.0 GHG M ONITORING

CO 2 emissions from the CFB B oilers will be measured by installing an exhaust gas flow monitoring system in accordance with the requirements of 40 CFR 75.10(a)(1) and a continuous CO 2 emission monitoring system in accordance with the requirements of 40 CFR §75.10(a)(3)(i). Emissions of CH 4 and N 2 O from the CFB boilers will be calculated annually based on the annual heat input and emission factors from Table C

- 2 to Subpart C of 40 CFR Part 98

CO 2 , CH 4 , and N 2 O emissions from the auxiliary boilers and the propane vaporizers will be calculated annually based on emission factors from Tables C

- 1 and C

- 2 of 40 CFR Part 98, Subpart C, General Stationary Fuel Combustion Sources

. CH 4 emissions from natural gas piping fugitives will be calculated annually based on emission factors from Table W

- 1A of 40 CFR Part 98, Subpart W, Petroleum and Natural Gas Systems.

SF 6 emissions from the generator circuit breakers will be calculated annually in accordance with the mass balance approach provided in equation DD

- 1 of the Mandatory Greenhouse Gas Reporting Rules for Electrical Transmission and Distribution Equipment.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

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010303 

## APPENDIX A COPY OF PERMITS 85013, HAP48, AND PSDTX1138

### TEXAS COMMISSION ON ENVIRONMENTAL QUALITY AIR QUALITY PERMIT

A PERMIT IS HEREBY ISSUED TO

Las Brisas Energy Center, LLC AUTHORIZING THE CONSTRUCTION AND OPERATION OF Petroleum Coke-Fired Electric Generation Facility LOCATED ATCorpus Christi, Nueces County, Texas

LATITUDE 27° 49' 11" LONGITUDE 97° 28' 34"

1. Facilities covered by this pemlit shall be constructed and operated as specified in the application for the pemlil. All representations regarding construction plans and operation procedures contained in the permit application shall be conditions upon which the permit is issued. Variations from these representations shall be unlawful unless the permit holder first makes application to the Texas Commission on Environmental Quality (commission) Executive Director to amend this pemlit in that regard and such amendment is approved. [Title 30 Texas Administrative Code § 116.116 (30 TAe § 116.116)J 2. Voiding of Permit. A pemlit or pennit amendment is automatically void if the holder fails to begin construction within 18 months of the date of issuance, discontinues construction for more than IS months prior to completion, or fails to complete construction within a reasonable time. Upon request, the executive director may grant an IS-month extensioll. Before the extension is granted the pcnnit may be subject to revision based on best available control technology, lowest achievable emission rate, and netting or offsets as applicable. One additional extension of up to IS months may be granted if the pemlit holder demonstrates that emissions from the facility will comply with all rules and regulations of the commission, the intent of the Texas Clean Air Act (TCAA), including protection of the public's health and physical property; and (b)(l)the pennit holder is a party to litigation not of the pemlit holder's initiation regarding the issuance of the penn it; or (b)(2) the permit holder has spent, or committed to spend, at leastiO percent of the estimated total cost of the project up to a maximum ofSS million. A pennit holder granted an extension under subsection (b)(I) of this section may receive one subsequent extension if the pennit holder meets the conditions of subsection (b)(2) of this section. [30 TAC § 116.120(a), (b) and (c)]
3. Construction Progress. Start of construction, construction inlemlptions exceeding 45 days, and completion of construction shall be reported to the appropriate regional office of the commission not later than 15 working days after occurrence of the event. (30 TAC § 116.1IS(b)(2)(A)]
4. Start-up Notification. TIle appropriate air program regional office shall be notified prior to the commencement of operations of the facilities authorized by the permit in such a manner that a representative of the commission may be present. The pennit holder shall provide a separate notification for the commencement of operations for each unit of phased construction, which may involve a series of units commencing operations at different times. Prior to operation of the facilities authorized by the pennit, the permit holder shall identify to the Office of Permitting and Registration the source or sources of allowances to be utilized for compliance with Chapter 10 I, Subchapter H, Division 3 of this title (relating to Mass Emissions Cap and Trade Program). [30 TAC § 116.IIS(b)(2)(B)]
5. Sampling Requirements. Ifsampling is required, the pemlit holder shall contact the commission's Office of Compliance and Enforcement prior to sampling to obtain the proper data forms and procedures. All sampling and testing procedures must be approved by the executive director and coordinated with the regional representatives of the commission. The pemlit holder is also responsible for providing sampling facilities and conducting the sampling operations or contracting with an independent sampling consultant. [30 TAC § 116.115(b)(2)(C)]
6. Equivalency of Methods. The pennit holder must demonstrate or otherwise justity the equivalency of emission control methods, sanlpling or other emission testing methods, and monitoring methods proposed as alternatives to methods indicated in the conditions of the pemlit. Alternative methods shall be applied for in '''Titing and must be reviewed and approved by the executive director prior to their use in fulfilling any requirements of the pemlit. [30 TAC § 1 16. I 15(b)(2)(D)]
7. Recordkeeping. The permit holder shall maintain a copy of the pem)it along with records containing the infomlation and data sufficient to demonstrate compliance with the pennit, including production records and operating hours; keep all required records in a file at the plant site. If, however, the facility nomtally operates unattended, records shall be maintained at the nearest staffed location within Texas specified in the application; make the records available at the request of personnel from the commission or any air pollution control program having jurisdiction; comply with any additional recordkecping requirements specified in special conditions attached to the pemlit; and retain information in the file for at least tv.'o years following the date that the information or data is obtained. [30 TAC § 116.l15(b)(2)(E)]
8. Maximum Allowable Emission Rates. The total emissions of air contaminants from any of the sources of emissions must not exceed the values stated on the table attached to the permit entitled "Emission Sources--Maximum Allowable Emission Rates." [30 TAC § 116.11S(b)(2)(F)]
9. Maintenance of Emission Control. The permitted facilities shall not be operated unless ali air pollution emission capture and abatement equipment is maintained in good working order and operating properly during nonnal facility operations. The pennit holder shall provide notification for upsets and maintenance in accordance with §§ 101.201, 101.211, and 101.221 of this title (relating to Emissions Event Reporting and Recordkeeping Requirements; Scheduled Maintenance, Startup, and Shutdown Reporting and Recordkeeping Requirements; and Operational Requirements). [30 TAC § 116.l1S(b)(2)(G)]
10. Compliance with Rules. Acceptance of a penn it by an applicant constitutes an acknowledgment and agreement that the pemtit holder will comply with all rules, regulations, and orders of the commission issued in confonnity with the TCAA and the conditions precedent to the granting of the pennit. If more than one state or federal rule or regulation or permit condition is applicable, the most stringent limit or condition shall govern and be the standard by which compliance shall be demonstrated. Acceptance includes consent to the entrance of commission employees and agents into the permitted premises at reasonable times to investigate conditions relating to the emission or concentration of air contaminants, including compliance with the pennit. [30 TAC § 116.l15(b )(2)(H)]
11. This pemlit may be appealed pursuant to 30 TAC § 50.139.
12. This pemlit may not be transferred, assigned, or conveyed by the holder except as provided by rule. [30 TAC § 116.IIO(e))
13. There may be additional special conditions attached to a permit upon issuance or modification of the permit. Such conditions in a pemit may be more restrictive than the requirements ofTitJe 30 of the Texas Administrative Code. [30 TAC § 116.115(c)]
14. Emissions from this facility must not cause or contribute to a condition of "air pollution" as defined in TCAA § 3S2.003(3) or violate TCAA § 382.0S5, as codified in the Texas Health and Safety Code. If the executive director detemlines that such a condition or violation occurs, the holder shall implement additional abatement measures as necessary to control or prevent the condition or violation.

TCEQ Docket No.: 2009·0033·AIR PERMITS 85013 HAP48 and PSDTXl138
Date:

____________ _ I;or the Commission

### SPECIAL CONDITIONS

Permit Numbers 85013, HAP48, and PSD· TX· 113 8

EMISSION RATES AND PERMIT REPRESENTATIONS

I. This pelmit covers only those sources of emissions listed in the attached table entitled "Emission Sources· Maximum Allowable Emission Rates," and those sources are limited to the emission limits and other conditions specified in that attached table. This permit authorizes planned start·up and shutdown (SS) activities that comply with the emission limits in the maximum allowable emission rates table (MAERT) and the opacity limit of Special Condition No. 10. Compliance with the annual emission limits shall be based on throughput for a rolling 12·month year rather than the calendar year.
2. Emission limits are based upon representations in the permit application dated May 19,2008, and subsequent updates dated October 3, November 12, December II, December 29, and December 31, 2008; and January 5, 2009.

FEDERAL APPLICABILITY

3. The Circulating Fluidized Bed (CFB) Boilers, identified as Emission Point Nos. (EPNs) CFB I, CFB2, CFB3, and CFB4, shall comply with applicable requirements of the U.S. Environmental Protection Agency (EPA) regulations in Title 40 Code of Federal Regulations (40 CFR) Part 60, Standards of Performance for New Stationary Sources, Subpart A, General Conditions, and Subpart Db, Standards of Performance for Industrial, Commercial, and Institutional Steam Generating Units.

4. The Auxiliary Boilers, identified as EPNs AUX·BOILI and AUX·BOIL2, shall comply with the applicable requirements of 40 CFR Part 60, Subpart A and Subpart Db, Standards of Performance for Industrial, Commercial, and Institutional Steam Generating Units.

5. The Stationary Diesel Engines, identified as EPNs ENG·EGl, ENG·EG2, ENG·FWMAIN, ENG·FWBI, ENG·FWB2, ENG·FWB3, ENG·FWB4, ENG·BFWPI, ENG·BFWP2, ENG·BFWP3, and ENG·BFWP4, shall comply with the applicable requirements of 40 CFR Part 60, Subpart A and Subpart 

## nn, Standards of Performance for Stationary Compression Ignition Internal Combustion Engines.

6. The Stationary Diesel Engines, identified as EPNs ENG·EGl, ENG·EG2, ENG·BFWPl, ENG·BFWP2, ENG·BFWP3, and ENG·BFWP4, shall comply with the initial notification requirements of 40 CFR 

### § 63.6645(h), as specified in 40 CFR Part 63, SubpartZZZZ, National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines, § 63.6590(b)(1)(i).

### SPECIAL CONDITIONS Pelmit Numbers 85013, HAP48, and PSD-TX-I138 Page 2

7. If any condition of this permit is more stringent· than the regulations identified in Special Condition Nos. 3 through 6, then for the purposes of complying with this permit, the permit shall govern and be the standard by which compliance shall be demonstrated.

FUEL SPECIFICATIONS, OPERATING LIMITATIONS, PERFORMANCE STANDARDS, AND CONSTRUCTION SPECIFICATIONS

8. Fuel fired in the CFB Boilers (EPNs CFBl, CFB2, CFB3, and CFB4) shall be limited to:



### A. Petroleum coke with:
(I) elemental sulfur content not to exceed a 12-month rolling average of 4.9 pounds sulfur per million British thermal units (lb/MMBtu) of heat input, with the heat input based on fuel higher heating value (HHV); and
(2) trace metal concentrations not to exceed the concentration limitations identified in Attachment A of this permit.

B. Pipeline-quality. natural gas.

C. Propane.

D. Use of any other fuel will require prior approval from the permitting authority.

E. Upon request by the Executive Director of the Texas Commission on Environmental Quality (TCEQ) or any air pollution control program having jurisdiction, the holder of this permit shall provide a sample and/or an analysis ofthe fuel fired in the CFB Boilers
or shall allow air pollution control agency representatives to obtain a sample for analysis.

9. The CFB Boilers (EPN s CFB I, CFB2, CFB3, and CFB4) shall each be limited to a maximum heat input of3,080 MMBtu/hr, averaged over a calendar month, based on the HHV of the fuel fired.

10. Opacity of emissions from EPNs CFB I, CFB2, CFB3, and CFB4 must not exceed 10 percent, averaged over a six-minute period, except for those periods described in Title 30 Texas Administrative Code 

### § 11 1.111 (a)(l)(E) [30 TAC 

### § 11 1.1 11 (a)(l)(E)], 40 CFR Part 60, § 60.l1(c), or as otherwise allowed by rule or statute.

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-I138 Page 3

II. Emissions from the CFB Boilers (EPNs CFBI, CFB2, CFB3, and CFB4) shall not exceed the performance standards in the following tables. The performance standards in these tables shall apply at all times except during periods of start-up and shutdown as identified in the permit application.



### A. Standards demonstrated by Continuous Emissions Monitoring Systems (CEMS):



### Pollutane Performance Standard Compliance Averaging

. . 

### (lbIMMBtnl· Period

.. NO x 

### 0.10 Hourly NO x 

### 0.070 30-day rolling S02 0.114 30-day rolling S02 0.086 12-month rolling CO 0.10 12-month rolling Hg 0.57(10,6) 12-month rolling

.. 

### Performance Standard . 

### (ppmv) NH3 10 ppmv Hourly

. 

### NH3 5ppmv !2-month rolling

B. Standards demonstrated by Reference Method 3 (RM) testing:

... .. . 

### Performance Standard Compliance Pollutant' (lbIMMBtu)2 Demonstration Period. PMlPM,o (fiont- 0.011 3-hour average half catch)


### PM/PM IO 

### total 0.025 4 

### 3-hour average
VOC 0.0050 3-hour average
H 2 

### SO 4 

### 0.0045 3-hour average

HC! 0.0044 3-hour average
HF 0.00038 3-hour average

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-1138 Page 4

Notes:

1 NO x _

SO, 

### CO

- PM

- nitrogen oxides sulfur dioxide carbon monoxide particulate matter PM lO
- 

### VOC

- H, S0 4

- HCI PM ';lOpm in diameter volatile organic compounds sulfuric acid mist hydrogen chloride HF

- hydrogen fluoride Hg

- mercury NH,- ammonia

j IblMMBtu

- pounds of emissions per million Btu ofheat input. Heat input is based on fuel HHV.

ppmv
- patts per million by volume, dry, adjusted to 3 percent oxygen (0,).

3 RM

_ EPA Reference Methods, based on the average of three stack sampling runs to be conducted as

prescribed by Special Condition Nos. 28 and 37.

4 Total PMlPM lO including back-half(condensibles) catch of sampling train.


### 12. In the event that a CEMS for NO x 

### is not operating for a period longer than one hour while a CFB boiler is operating, the permit holder shall operate at no less than the ammonia feed rate to the selective non-catalytic reduction (SNCR) system that was established during a successful initial performance test (adjusted for load) or at the NOx-compliant feed rate that was measured prior to the loss of the CEMS (adjusted to load), whichever feed rate is higher.

13. In the event that a CEMS for S02 is not operating for a period longer than one hour while a CFB boiler is operating, the permit holder shall operate at no less than the limestone feed rate to the boiler and lime feed rate to the polishing scrubber that were established during a successful initial performance test (adjusted for load) or at the SOrcompliant feed rates that
were measured prior to the loss of the CEMS (adjusted to load), whichever feed rates are higher.

14. 

### A. The holder of this permit shall operate the CFB Boiler and associated air pollution control equipment in accordance with good air pollution control practice to minimize emissions during statt-up and shutdown (SS) activities, by operating in accordance with a written SS plan. The plan shall include detailed procedures for review of relevant operating parameters of the CFB Boilers .and associated air pollution control equipment during SS to make adjustments to minimize excess emissions. The plan shall also address readily foreseeable start-up scenarios, including hot start-ups, and provide for appropriate review of the operational condition of the boiler before initiating start-up.


### B. In order to limit maximum hourly emissions of S02, the start-up of the CFBs must be sequenced so that only one CFB at a time is firing petroleum coke while operating in start-up mode.

C. No bypassing of a CFB baghouse is allowed while the CFB is firing petroleum coke, regardless of whether the CFB is operating in start-up or shutdown mode.

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-I138 Page 5

D. Only planned and routine start -up/shutdown operations are authorized by this permit. Emissions resulting from any unscheduled and/or unplanned start-up/shutdown activity associated with an upset (emissions event) are not authorized by this pelmit.

15. The CFB Boiler Stacks (EPNs CFBI, CFB2, CFB3, and CFB4) shall be approximately 500 feet tall with an exit diameter of approximately 16 feet. Stack sampling ports and platform( s) shall be constructed on each CFB boiler stack as specified in the attachment entitled "Chapter 2, Stack Sampling Facilities," or an alternate design may be approved by the TCEQ Corpus Christi Regional Director.

16. The Auxiliary Boilers (identified as EPNs AUX-BOILl and AUX-BOIL2) shall meet the following specifications:



### A. Emissions, averaged over 3 hours of operation, while operating at greater than 25 percent load, shall not exceed:
(1) NO x - 

### 0.035IbIMMBtu;
(2) CO

- 50 ppmvd, at 3 percent O 2 ; 

### and
(3) Filterable PM

- 0.0019IbIMMBtu.



### B. Emissions, averaged over three hours of operation, during start-up, shutdown, or while operating at less than 25 percent load, shall not exceed:
(I) 

### NO x - 

### 0.10 IbIMMBtu; and
(2) CO

- 500 ppmvd, 3 percent oxygen

C. Opacity of emissions shall not exceed 5 percent, averaged over a six-minute period.

D. Fuel shall be limited to pipeline-quality natural gas.

E. Operation of each Auxiliary Boiler shall be limited to a maximum of a 28.5 percent annual capacity factor. Capacity factor is the ratio between the actual heat input during
a period of 12 consecutive calendar months and the potential heat input had the boiler operated for 8,760 hours during that 12-month period at the maximum design heat input capacity.

17. The Propane Vaporizers (identified as EPNs PROP-VAPI and PROP-VAP2) shall meet the following specifications:

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-I138 Page 6



### A. Emissions, averaged over 3 hours of operation, shall not exceed:
(I) 

### NO x - 

### 0.10 IbIMMBtu;
(2) CO

- 100 ppmvd, at 3 percent O 2 ; 

### and
(3) Filterable PM

- 0.0019 IbIMMBtu.

B. Opacity of emissions shall not exceed 5 percent, averaged over a six-minute period.

C. Fuel shall be limited to propane.

D. Operation of each propane vaporizer shall be limited to a maximum of a 28.5 percent annual capacity factor. Capacity factor is the ratio between the actual heat input during
a period of 12 consecutive calendar months and the potential heat input had the boiler operated for 8,760 hours during that 12-month period at the maximum design heat input capacity.

18. The 1,600-kW Diesel-Fired Emergency Generators (identified as EPNs ENG-EGl and ENG-EG2) and the 2,000-hp Diesel-Fired Boiler Feed Water Pumps (identified as EPNs ENG-BFWPI, ENG-BFWP2, ENG-BFWP3, and ENG-BFWP4) shall meet the following specifications:

A. Fuel shall be limited to diesel engine fuel containing no more than 500 parts per million (ppm) by weight sulfur. Purchased diesel engine fuel shall comply with the EPA standards for nonroad diesel fuel in 40 CFR Part 80, Regulation of Fuels and Fuel Additives, in effect at the time of purchase.

B. Operation of each generator and pump shall be limited to a maximum of 500 hours per year.

19. The 360-hp Diesel-Fired Fire Water Pump (identified as EPN ENG-FWMAIN) and the 100-hp Diesel-Fired Fire Water Pumps (identified as EPNs ENG-FWBI, ENG-FWB2, ENG-FWB3, and ENG-FWB4) shall meet the following specifications:



### A. Fuel shall be limited to diesel engine fuel containing no more than 500 ppm by weight sulfur. Purchased diesel engine fuel shall comply with the EPA standards for nonroad diesel fuel in 40 CFR Pat1 80, Regulation of Fuels and Fuel Additives, in effect at the time of purchase.

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-I138 Page 7

B. Operation of each pump shall be limited to a maximum of 500 hours per year unless a greater number of hours of operation is required to fight a fire.

CHEMICAL AND FUEL STORAGE

20. Anhydrous ammonia storage is subject to the following requirements.

A. Maximum on-site storage is limited to the two pressure tanks identified in the permit application, each with a nominal capacity of 10,000 gallons.

B. The tanks shall be located within
(1) 

### a physical banier to vehicular traffic; and
(2) a containment system which is capable of holding the entire volume of material stored.

C. Piping and unloading points shall be protected from impact by falling objects.

D. Each tank vent valve shall be equipped with an alarm which will notify personnel that the relief valve has opened.

E. Tanks shall be vapor balanced to the transport vessel during all tank filling operations. The vapor retum line shall be purged back to either the transport vessel or the storage tank after every tank loading operation and prior to disconnection of the line. Interlocks shall be installed so that the unloading pump will not lUn unless the vapor return line to the transpOit vessel is connected.

F. All plant personnel assigned to anhydrous annnonia injection operations shall participate in continuing training in safety guidelines for the handling of anhydrous annnonia, to be conducted no less frequently than once every two years; new and transfened personnel shall complete all initial training required for their specific assignments prior to assumption of their new duties.

G. Overhead activity involving the lifting of heavy equipment above the anhydrous ammonia storage area shall not be pennitted.

H. The holder of this permit shall maintain a complete emergency response plan at the plant

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-1138 Page 8

site that describes the course of action to be taken by personnel in the event of an anhydrous ammonia tank or line mpture, or a severe anhydrous ammonia leak. This plan shall include water-mitigation methods, notification of the proper civil authorities, and any potentially affected residences and any other appropriate organizations. This plan shall be made available upon request to representatives of the TCEQ or any local program having jurisdiction.

21. Audio, olfactory, and visual checks for ammonia leaks shall be made once per shift within the operating area.
A. 

### No later than one hour following detection of a leak, plant personnel shall take one or more of the following actions:
(I) Locate and isolate the leak; and/or
(2) Stop the leak by bypassing the leaking equipment or taking equipment out of service.

B. If the leaking equipment cannot be repaired or replaced within 6 hours, use clamping procedures to prevent the leak until replacement or repair can be performed.

22. In any consecutive 12-month period, the holder of this permit shall not receive more than the following quantities of diesel fuel:



### . .. . 

# .'.



# . , .. 12-Month
I. 

### Tankl'lumber Throughput

...... (Gallons)

.. ... 

# ,
TNK-EGI 2,734

TNK-EG2 2,734
TNK-FWMAIN 9,841
TNK-FWBI 54,674
TNK-FWB2 54,674 •


### TNK-FWB3 54,674
TNK-FWB4 54,674

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD-TX-I138 Page 9

. . . 

### 12-Month Tank Number Throughput

. 

### (Gallons)

TNK-BFWPI 63,100
TNK-BFWP2 63,100
TNK-BFWP3 63,100
TNK-BFWP4 63,100

MATERIAL HANDLING OPERATING LIMITATIONS AND STANDARDS

23. Pennanent plant roads shall be paved with a cohesive hard surface which can be cleaned by sweeping or washing. Other roads shall be sprinkled with water and/or surface crusting agents as necessary to maintain compliance with all TCEQ rules and regulations.

24. No visible emissions may leave the plant property. If visible emissions do leave the plant property, fmther controls or measures shall be installed and/or implemented to limit visible emissions. A trained observer with delegation from the Executive Director of the TCEQ may detelmine compliance with this special condition by 40 CFR Pmt 60, Appendix A, RM 22, or equivalent. As represented in the pennit application, petroleum coke and limestone will be brought into the facility property via enclosed conveyors only. Lime, soda ash, sand, and activated carbon will be unloaded pneumatically from trucks and conveyed to bins or silos equipped with baghouses. Fly ash from the boiler exhaust baghouses and bottom ash from the boilers will be pneumatically transferred to storage silos. From the storage silos, the fly ash and bottom ash will be conveyed pneumatically and loaded to tank trucks use a loading spout that creates a seal so that there will be no leakage of fly ash or bottom ash during the loading of tank trucks. The loading spout will utilize a fabric sJu'oud to pull the dust or ash laden air from the tank huck back into the ash silos, where it will be exhausted through the silo baghouses. No materials may be stored in open stockpiles on the facility property. Any spillage of material shall be cleaned up as soon as possible and handled in such a way as to minimize emissions.

25. As determined by a certified opacity observer with delegation from the Executive Director of the TCEQ and according to 40 CFR Pm 60, Appendix A, Reference Method 9, or equivalent, opacity of emissions from any single fabric filter baghouse stack listed in Special Condition Nos. 26 and 27, and from load out of fly ash and bottom ash from the storage silos to trucks, shall not exceed 5 percent averaged over a six -minute period. Continuous demonstration of compliance with this special condition is not required.

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD- TX-I138 Page 10

26. Material handling baghouses, designed to meet an emission limit of O.oJ 

### grain PM per dry standard cubic foot of exhaust, properly installed and in good working order, shall control PM emissions from the following sources:

, 

# .'

" ,',' ," ,**~** 

### " Source

, - I '.' 

### 1':PN.,

, , 

### Limestone Bunker No. 1 SILO-LMSTI
Limestone Bunker No.2 SILO-LMST2 '
Limestone Bunker No.3 SILO-LMST3
Limestone Bunker No.4 SILO-LMST4
Carbon For ACI Silo No.1 SILO-ACII
Carbon For ACI Silo No.2 SILO-ACI2
Carbon For ACI Silo No.3 SILO-ACI3
Carbon For ACI Silo No.4 SILO-ACI4
Lime Silo No. 1 SILO-LIME 1
Lime Silo No.2 SILO-LIME2
Lime Silo No.3 SILO-LIME3
Lime Silo No.4 SILO-LIME4
Lime Silo No.5 SILO-LIMES
Lime Silo No.6 SILO-LIME6
Lime Silo No.7 SILO-LIME7
Lime Silo No.8 SILO-LIME8
Unit 1 Sand Day Bin BIN-SANDI
Unit 2 Sand Day Bin BIN-SAND2
Unit 3 Sand Day Bin BIN-SAND3

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD-TX-I138 Page 11

. Source

. 

# . . 

### Unit 4 Sand Day Bin

Water Treatment Lime Silo
Water Treatment Soda Ash Silo 

### .EPN .


### BIN-SAND4
WT-L1ME
WT-SODA

27. Material handling baghouses, designed to meet an emission limit of 0.005 grain PM per dry standard cubic foot of exhaust, properly installed and in good working order, shall control PM emissions from the following sources:

. . 

# . ..


# .....
. .

.. 

### ... . . Source

...

. 

## EPN Fly Ash Silo No. 1 SILO-FAl Fly Ash Silo No.2 SILO-FA2 Fly Ash Silo No.3 SILO-FA3 Fly Ash Silo No.4 SILO-FA4

Bottom Ash Silo No. 1 SILO-BAl

Bottom Ash Silo No.2 SILO-BA2

Bottom Ash Silo No.3 SILO-BA3

Bottom Ash Silo No.4 SILO-BA4
Coke Silo No. 1 SILO-COKEl
Coke Silo No.2 SILO-COKE2
Coke Silo No.3 SILO-COKE3
Coke Silo No.4 SILO-COKE4
Coke Silo No.5 SILO-COKE5
Coke Silo No.6 SILO-COKE6
Coke Silo No.7 SILO-COKE7

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-I138 Page 12



## ......•.. .'-- 

# .

. 

### Source.
Coke Silo No.8

INITIAL DEMONSTRATION OF COMPLIANCE . ..



### . EPN
SILO-COKE8

28. The holder of this permit shall perfolm initial stack sampling and other testing to establish the actual quantities of air contaminants being emitted into the atmosphere. Unless otherwise specified in this Special Condition No. 28, the sampling and testing shall be conducted in accordance with the methods and procedures specified in Special Condition No. 29. The holder of this permit is responsible for providing sampling and testing facilities and conducting the sampling and testing operations at his expense. The TCEQ Executive Director or his designated representative shall be afforded the opportunity to observe all such sampling.

A. For the CFB Boilers (EPNs, CFBI, CFB2, CFB3, and CFB4):
(1) Demonstrate compliance with the performance standards of Special Condition No. lIB and the hourly emission rates of the MAERT, applicable to normal operations, using the average of three one-hour stack sampling test runs for each contaminant.
(2) Air contaminants to be sampled and analyzed under (1) above include: NO" S02, CO, VOC, H 2 S0 4 , 

### HCI, HF, PM, PMJQ, NH 3 , 

### and Hg. Diluents to be measured include O 2 or carbon dioxide (C0 2 ),
(3) Demonstrate compliance with the performance standards of Special Condition No. 10 applicable to normal operations, using the average of 30 six-minute readings as provided in 40 CFR § 60.II(b).
(4) Demonstrate compliance with 40 CFR Part 60, Subparts A and Db, for NO" S02, PM, and opacity. For NO x 

### and S02, the 30-day test results shall also be used to demonstrate compliance with the 30-day performance specifications for NO, and S02 in Special Condition No. IIA.
(5) Demonstrate compliance with the Ib/MMBtu 

### performance standards listed on Attachment A and the Ib/hr emission rate for lead listed on the MAERT using the average of three one-hour stack sampling test runs.

### SPECIAL CONDITIONS Pennit Nwnbers 85013, HAP48, and PSD-TX-I138 Page 13

(6) Boiler load during testing shall be maintained as follows.
(a) Operate at maximum firing rates for the atmospheric conditions occurring during the test as measured by millions of pounds of steam generated per hour or MW of electric generator output. If during subsequent operations the steam generated as measured by millions of pounds of steam generated per hour or MW of electric generator output is greater than that recorded during the test, stack sampling shall be performed at the new operating condition within 150 days. This sampling may be waived by the TCEQ Air Section Manager of the appropriate TCEQ regional office. At no time may the emission rate exceed the rates specified in the MAERT.
(b) During 30-day average emission testing, the boiler load does not have to be maximum, but the load must be representative of future operating conditions and must include at least one 24-hour period at full load.

B. For the Auxiliary Boilers (EPNs AUX-BOILl and AUX-BOIL2):
(1) Demonstrate compliance with the NO x , 

### CO, and filterable PM perfonnance standards of Special Condition No. 16A and the hourly NO x 

### and CO emission rates of the MAERT, using the average of three, one-hour stack sampling test runs for each contaminant.
(2) Demonstrate compliance with the opacity limitation of 40 CFR Part 60 Subpart Db and Special Condition No. 16C.
(3) Demonstrate compliance with the S02 emission rate of the MAERT through fuel sampling to demonstrate use of pipeline quality natural gas. (4) Demonstrate compliance with the VOC emission rate of the MAERT through operation of the auxiliary boilers within their design limitations.

C. For the Propane Vaporizers (EPNs PROP-YAP! and PROP-VAP2):
(1) Demonstrate compliance with the NO" CO, and filterable PM perfonnance standards ofSpecia! Condition No. !7 A and the hourly NO x 

### and CO emission rates of the MAERT, using the average ofthree, one-hour stack sampling test runs for each contaminant.
(2) Demonstrate compliance with the opacity limitation of Special Condition No. !7B.

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD-TX-1138 Page 14

(3) Demonstrate compliance with the SOl emission rate of the MAERT through fuel sampling of the propane. (4) Demonstrate compliance with the VOC emission rate of the MAERT through operation of the propane vaporizers within their design limitations.

D. For at least two material handling/storage baghouses, one from Special Condition No. 26 and one from Special Condition No. 27, to be selected by the Corpus Christi Regional Director of the TCEQ, or his designated representative, sample PM emissions using Reference Method 5 testing to show compliance with the emission limits of Special Condition Nos. 26 and 27.

E. For the Diesel-Fired Emergency Generators (identified as EPNs ENG-EGl and ENG-EG2) and the Diesel-Fired Boiler Feed Water Pumps (identified as EPNs ENG-BFWPl, ENG-BFWP2, ENG-BFWP3, and ENG-BFWP4) demonstrate compliance with the emission rates of the MAERT by showing compliance with the requirements of Special Condition No. 18. For the Diesel-Fired Fire Water Pump (identified as EPN ENG-FWMAlN) and the Diesel-Fired Fire Water Pumps (identified
as EPNs ENG-FWB1, ·ENG-FWB2, ENG-FWB3, and ENG-FWB4) demonstrate compliance with the emission rates of the MAERT by showing compliance with the requirements of Special Condition No. 19.

F. For the Cooling Towers (identified as EPNs CTWR1 and CTWR2) demonstrate compliance with the emission rates of the MAERT by maintaining records that demonstrate that the drift eliminators are designed to limit drift as specified in the pennit application, and by inspection of the modules, selected by the TCEQ Corpus CIu'isti Regional Director or his designated representative, for consistency with the specified design, flow bypassing the drift eliminators, and damage to the drift eliminators. The manufacturer's specifications and drawings of the internals shall be provided to facilitate inspection.

G. Requests to waive testing for any pollutant specified in this condition shall be submitted to the TCEQ Office ofPennitting and Registration, Air Pennits Division. Test waivers and alternate or equivalent procedure proposals for New Source Perfonnance Standards testing which must have EPA approval shall be submitted to the TCEQ Corpus Christi Regional Office.

H. For each CFB Boiler, sampling as required by this condition shall occur within 30 days after the particular boiler achieves a fuel firing rate of 3 ,080 MMBtulhr, but no later than

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-I138 Page 15

180 days after initial start-up. The first boiler operating day of 30-day average initial performance testing required by 40 CFR 

### § 60.45b( c) must commence within this time.

I. 

### The deadlines established by this condition may be extended by the TCEQ Corpus Christi Regional Office for good cause shown.

TEST METHODS AND PROCEDURES

29. A. Sampling shall be conducted in accordance with the appropriate procedures of the TCEQ Sampling Procedures Manual, EPA Methods in 40 CFR Part 60, Appendix A and 40 CFR Part 51, Appendix M, EPA Conditional Test Methods, and American Society for Testing and Materials (ASTM) as follows:
(I) Appendix A, Methods 1 through 4, as appropriate, for exhaust flow, diluent, and moisture concentration;
(2) Appendix A, Method 5, 5a through 5i, or 17, modified to include back-half condensibles, for the concentration of PM;
(3) Appendix A, Method 5, 5a through 5i, or 17, for the filterable concentration of PM (front-half catch);
(4) Appendix A, 

### Method 6, 6a, 6c, or 8, for the concentration of S02;
(5) Appendix A, Method 7E for the concentrations of NO, and O 2 , or equivalent methods;
(6) Appendix A, Method 8 or a modified Method 8 for H2S04;
(7) Appendix A, Method 9 for opacity, as provided in 40 CFR 

### § 60.11 (b);
(8) Appendix A, Method 10 for the concentration of CO;
(9) Appendix A, Method 19, for applicable calculation methods;
(10) Appendix A, Method 25A, modified to exclude methane and ethane, for the concentration ofVOC (to measure total carbon as propane);
(II) Appendix A, Method 26 or 26A for HCI and HF;

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD- TX-I138 Page 16

(12) EPA Conditional Test Method 27 (CTM-027), for NH J ; 

### (13) Appendix A, Method 29 for the metals listed in Attachment A;
(14) Appendix M, Methods 20lA and 202, or Appendix A, Reference Method 5, modified to include back-half organic condensables, for the concentration of PM less than 10 microns in diameter, PMlO. For inorganic condensables, a parallel controlled condensation method (NCASI Method 8A) shall be used. (Any method, procedures, or apparatus not identified in the CFR must be approved by the TCEQ and EPA prior to use);
(15) Appendix M, Methods 20lA or Appendix A, Reference Method 5, for the filterable concentration of PM less than 10 microns in diameter, PM lO (front-half catch); and
(16) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, Particle-Bound, and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (also known as the Ontario Hydro Method), Appendix A, Method 30A or 30B, or other approved EPA methods.

B. 

### Any deviations from the procedures in 

### A. must be approved by the Executive Director of the TCEQ or his designated representative prior to sampling.

C. The TCEQ Corpus Christi Regional Office shall be given notice as soon as testing is scheduled but not less than 45 days prior to sampling to schedule a pretest meeting.
(I) The notice shall include:
(a) Date for pretest meeting. (b) Date sampling will occur. (c) Name of firm conducting sampling. (d) Type of sampling equipment to be used. (e) Method or procedure to be used in sampling. (f) 

### Projected date of commencement of the 30-day rolling average initial performance tests for S02 and NO x , 

### in accordance with 40 CFR 

### § 60.45b(c) and Special Condition No. IIA.
(2) The purpose ofthe pretest meeting is to review the necessaty sampling and testing procedures, to provide the proper data forms for recording pertinent data, and to

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-I138 Page 17

review the fonnat procedures for submitting the test reports. The pelmit holder shall present at the pretest meeting the manner in which stack sampling will be executed in order to demonstrate compliance with emission standards found in this permit and 40 CFR Part 60, Subpart Db.
(3) Prior to the pretest meeting, a written proposed description of any deviation from sampling procedures specified in pennit conditions or TCEQ, EPA or ASTM sampling procedures shall be made available to the TCEQ. The TCEQ Corpus Christi Regional Director shall approve or disapprove of any deviation from specified sampling procedures.

D. Infonnation in the test repOlt shall include the following data for each test run: (I) 

### hourly petroleum coke firing rate (in tons);
(2) average petroleum coke Btu (HHV)/lb as-received and dry weight;
(3) average steam production rate (in millions of pounds per hour) or average generator output (in MW);
(4) daily sulfur content and heat content of the fuel measured in accordance with EPA Reference Method 19 to show compliance with 40 CFR Part 60, Subpart Db;
(5) control device operating rates, including SNCR reagent injection and solids injection rates (limestone, lime, and activated carbon);
(6) emissions in the units of the limits of this permit, lblhr and Ib/MMBtu, and three-hour or 30-day average, as appropriate; and
(7) any additional records deemed necessary during the stack sampling pre-test meeting.

E. Two copies of all final sampling reports shall be forwarded to the TCEQ within 60 days after sampling is completed. Sampling reports shall comply with the attached conditions of Chapter 14 of the TCEQ Sampling Procedures Manual. The repOlts shall be distributed as follows:

One copy to the TCEQ Corpus Christi Regional Office. One copy to the TCEQ Austin Office of Permitting and Registration, Air Pennits Division.

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD-TX-I138 Page 18

F. The deadlines established by this condition may be extended by the TCEQ Corpus Christi Regional Office for good cause shown.

CONTINUOUS DEMONSTRATION OF COMPLIANCE

30. The holder of this permit shall install, calibrate, maintain, and operate continuous emission monitoring systems (CEMS) to measure and record the concentrations of NO x , CO, and SOz from EPNs CFB 1, CFB2, CFB3, and CFB4. Diluents to be measured include 

### Oz or 

### COz. The CEMS data shall be used to detennine continuous compliance with the NO x , CO, and SOz emission limitations in Special Condition No.3 (NOx and SOz), Special Condition No. l1A, and the attached MAERT. Continuous compliance with the perfonnance standards of Special Condition No. llA shall commence on the first boiler operating day of the 30-day initial performance testing required by NSPS Subpart Db.



### A. The CEMS shall meet the design and perfonnance specifications, pass the field tests, and meet the installation requirements and the data analysis and reporting requirements specified in the applicable Perfonnance Specification Nos. 1 through 9, 40 CFR Part 60, Appendix B or an acceptable EPA alternative. If there are no applicable perfonnance specifications in 40 CFR Part 60, Appendix B, contact the TCEQ Office of Pennitting and Registration, Air Pennits Division in Austin for requirements to be met.

B. The holder of this pennit shall assure that the CEMS meets the applicable quality
assurance requirements specified in 40 CFR Part 60, Appendix F, Procedure 1, or an acceptable EPA alternative. Relative accuracy exceedances, as specified in 40 CFR Part 60, Appendix F, 

### § 5.2.3, any CEMS downtime, and all cylinder gas audit exceedances of ±15 percent accuracy shall be reported semiannually to the TCEQ Corpus Christi Regional Director; necessary con'ective action shall be taken on a timely basis. Supplemental stack concentration measurements may be required at the discretion of the TCEQ Corpus Christi Regional Director.

C. The monitoring data shall be reduced to hourly average concentrations at least once every day, using nonnally a minimum of four equally-spaced data points from each one-hour period. The individual average concentrations shall be reduced to units of the pennit allowable emissions rate in pounds per hour at least once every day. Pound per hour data shall be summed on a monthly basis to tons per rolling 12 months and used to detennine compliance with the annual emissions limits of this pennit. If the CEMS malfunctions, then the recorded concentrations may be reduced to units of the pennit allowable as soon as practicable after the CEMS resumes nonnal operation.

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD-TX-I138 Page 19

D. The TCEQ Corpus Christi Regional Office shall be notified at least 30 days prior to any required relative accuracy test audits in order to provide it the opportunity to observe the testing.

E. If applicable, each CEMS will be required to meet the design and performance specifications, pass the field tests, and meet the installation requirements and data analysis and reporting requirements specified in the applicable perfonnance specifications in 40 CFR Part 75, Appendix A and B, as an acceptable alternative to paragraph A. of this condition.

F. Each CEMS shall be operational during 95 percent of the operating hours of the CFB Boiler, exclusive of the time required for zero and span checks. If this operational criterion is not met for a calendar qualler, the holder of this permit shall develop and implement a monitor quality improvement plan within the following calendar quarter. The plan should address the downtime issues to improve availability and reliability. The plan should provide additional assurance of compliance including record keeping of appropriate SNCR reagent and solids flow rates for monitor downtime periods.

31. The holder of this pennit shall install, calibrate, operate, and maintain a continuous opacity monitoring system (COMS) to measure and record the opacity of emissions from EPNs CFB I, CFB2, CFB3, and CFB4. The COMS data shall be used to detennine continuous compliance with the opacity emission limitations in Special Condition Nos. 3 and 10.



### A. The COMS shall satisfy all of the Federal NSPS requirements for COMS as specified in 40 CFR Part 60, Appendix B, Performance Specification 1 (PS-l). In order to demonstrate compliance with PS-l, the COMS shall meet the manufacturer's design and perfonnance specifications, and undergo perfonnance evaluation testing as outlined in 40 CFR Subpart A, 

### § 60.13. The TCEQ Corpus Christi Regional Director shall be notified 30 days prior to the certification.

B. The COMS shall be zeroed and spanned daily as specified in 40 CFR 

### § 60.13. Corrective action shall be taken when the 24-hour span drift exceeds two times the amounts specified in PS-I, or as specified by the TCEQ ifnot specified in PS-l.

C. If the EPA promulgates a quality assurance, quality control standard for the COMS, a Quality Assurance Plan (QAP) shall be prepared in accordance with the EPA standard for the COMS and adhered to, within six months after promulgation. The QAP shall be maintained to reflect changes to component technology. At the request of the TCEQ Corpus Christi Regional Director, the holder of this pennit shall submit documentation

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD-TX-I138 Page 20

demonstrating compliance with these standards.

D. The data shall be reduced to six-minute opacity averages, using a minimum of 36 equally-spaced data points from each six-minute period, as specified in 40 CFR 

### § 60.13.

E. The COMS shall be operational during 95 percent of the operating hours of the CFB Boiler, exclusive of the time required for zero and span checks. If this operational criteria is not met for a calendar quarter, the holder of this pennit shall develop and implement a monitor quality improvement plan within the following calendar quarter. The plan should address the downtime issues to improve availability and reliability. The plan should provide additional assurance of compliance including EPA Reference Method 9 support during daytime monitor downtime periods and parametric support for nighttime monitor downtime periods.

F. Recertification, if required, shall be based on the requirements of 40 CFR Part 60, Appendix B, PS-I in effect at the time of initial certification.

32. The holder of this permit shall install, calibrate, operate, and maintain CEMS to measure and record the concentration ofNH 3 from EPNs CFBI, CFB2, CFB3, and CFB4. The NH3 concentrations shall be corrected and reported in accordance with Special Condition No. IIA. The CEMS data shall be used to detennine continuous compliance with the NH3 perfonnance specifications in Special Condition No. IIA and the MAERT. Any other method used for measuring NH3 slip shall require prior approval from the TCEQ Corpus Christi Regional Office, with consultation between the Regional Office and the TCEQ Air Pennits Division.

33. The holder of this pennit shall install, calibrate, operate, and maintain CEMS or sorbent trap monitoring system to measure and record the concentration of mercury from EPNs CFB I, CFB2, CFB3, and CFB4, as described in 40 CFR Pruts 60 and 75 (the rule versions in effect immediately prior to February 8, 2008 vacatur of Clean Air Mercury Rule). The CEMS data shall be used to demonstrate continuous compliance with the emission limitations of Special Condition No. IIA and the MAERT.

34. Each CEMS shall be operational on a rolling 12-month average for at least 95 percent of the corresponding operating hours of the CFB boiler it is designed to monitor (excluding time required for zero and span). If any CEMS fails to meet the perfonnance standards specified in this pennit, it shall be repaired or replaced as soon as reasonably possible.

35. The as-fired petroleum coke shall be sampled at least once per calendar quarter and analyzed for sulfur, metals, and HHV, to demonstrate on-going compliance after the initial

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD- TX-1138 Page 21

demonstration of compliance with the sulfur content limit of Special Condition No.8, the non-mercury metal performance standards identified in Attachment A of this pennit, and the emission rates for lead in the MAERT. The analyses shall be obtained from a NELAC (National Environmental Laboratory Accreditation Conference) accredited laboratory under the Texas Laboratory Accreditation Program.

36. The holder of this pennit shall install, operate, and maintain bag leak detection systems (BLDS) to monitor the perfonnance of the baghouses on CFB 1, CFB2, CFB3, and CFB4. The BLDS must meet the specifications and be operated according to the procedures of 40 CFR 

### § 60.48Da( 0)(4).

37. After the initial demonstration of compliance, on-going stack sampling ofEPNs CFB 1, CFB2, CFB3, and CFB4 for H 2 S0 4 , HCI, HF, VOC, and total PMlPM IO 

### shall be used to demonstrate ongoing compliance and shall meet the following specifications:

A. Stack sampling shall be perfonned once annually during periods of nonnal operation, except as follows:
(1) If the annual test does not establish compliance with a performance standard of Special Condition No. lIB, the holder of this pennit must conduct additional tests (under similar operating rates and fuel charge rates as used in the initial test, or under scenarios reviewed and approved by the TCEQ Corpus Christi Regional Office) during the year to be averaged with the previous test(s) to demonstrate compliance with Special Condition No. lIB; or (2) if, after three years of stack sampling, the average of the three annual stack sampling results for a pollutant is less than 70 percent of the applicable perfonnance standard identified in Special Condition No. lIB, then compliance stack sampling for such pollutant may be conducted once every three years.

B. Sampling required in A. of this special condition shall demonstrate compliance with the perfonnance standards of Special Condition No. lIB and the lblhr emission limits of the MAERT applicable to nonnal operations.

C. Sampling required in 

### A. of this special condition shall be conducted in accordance with the methods, procedures, and notification protocol specified in Special Condition No. 29.

D. Ongoing compliance with the H2S04, HF, HCI, VOC, and PMlPM IO 

### tons per year emission rates in the MAERT shall be demonstrated by calculating rolling 12-month annual emissions from emission factors (lbIMMBtu, HHV) obtained from the sampling

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD- TX-1138 Page 22

required in (A.) of this condition and the monthly total heat input (MMBtu, HHV) from petroleum coke.

38. Compliance with the following emission rates in the MAERT, applicable to periods of planned start-up and shutdown, shall be demonstrated as follows:



### A. Compliance with the lead, PM and PM IO 

### (front half and total) emission rates in the MAERT applicable during start -up and shutdown shall be demonstrated if the recorded pressure drop across the baghouse meets manufacturer guidelines for proper operation during start-up and shutdown.



### B. Compliance with the VOC emission rate in the MAERT applicable during start-up and shutdown shall be demonstrated if the CO emissions during start-up and shutdown are in compliance with the CO emission rate in the MAERT for start-up and shutdown.

C. Compliance with the H 2 S0 4 , 

### HF, and HCl emission rates in the MAERT for start-up and shutdown shall be demonstrated ifthe S02 emissions during start-up and shutdown are in compliance with the S02 emission rate in the MAERT for start-up and shutdown.

39. Following the initial demonstration of compliance, ongoing compliance with the emission limits for the sources and emission limitations listed in this condition shall be through source operation in accordance with manufacturer's specifications, or in accordance with written procedures that are shown to maintain operating conditions necessary for emission compliance. The Executive Director of the TCEQ or his designated representative may also require direct measurement of emissions using the sampling methods and procedures specified in Special Condition No. 29 to establish compliance with the limitations, in which
case the sampled emission rate will be used to determine compliance.

A. The Auxiliary Boilers (EPNs AUX-BOILl and AUX-BOIL2) emission limitations of Special Condition No. 16A and I6B and the MAERT.

B. The Propane Vaporizers (EPNs PROP- V API and PROP- V AP2) emission limitations of Special Condition No. 17 A and the MAERT.

C. The Diesel Engines (EPNs ENG-EGl, ENG-EG2, ENG-FWMAIN, ENG-FWBI, ENG-FWB2, ENG-FWB3, ENG-FWB4, ENG-BFWPl, ENG-BFWP2, ENG-BFWP3, and ENG-BFWP4) emission limitations in the MAERT.

40. Following the initial demonstration of compliance, ongoing compliance with the emission rates in, the MAERT for the Cooling Towers (EPNs CTWRI and CTWR2) will be based on

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD-TX-I138 Page 23

annual inspections of modules, and repair as necessary to maintain drift eliminator structural integrity and minimize bypassing of flow around drift eliminators.

41. Following the initial demonstration of compliance, ongoing compliance with the emission rates in the MAERT for the petroleum coke, ash, limestone, lime, sand, and carbon material handling baghouses will be demonstrated by annual opacity testing using Reference Method 9 for those EPNs listed in Special Condition Nos. 26 and 27. The Executive Director of the TCEQ or his designated representative may also require sampling conducted in accordance with the methods and procedures specified in Special Condition No. 29 to directly measure the lblhr emission rate, in which case the sampled lb/hr emission rate will be used to detennine compliance with the applicable emission rate in the MAERT.

42. Compliance with the emission rates in the MAERT for the Fuel Storage Tanks (EPNs TNK-FWMAIN, TNK-EGI, TNK-EG2, TNK-FWBI, TNK-FWB2, TNK-FWB3, TNK-FWB4, TNK-BFWPI, TNK-BFWP2, TNK-BFWP3, and TNK-BFWP4) will be demonstrated by compliance with Special Condition No. 22.

CASE-BY-CASE MACT
43. This case-by-case MACT permit, Pennit No. HAP48, establishes federally enforceable MACT emission limits for CO (CO is a sUlTogate of organic HAPs) and filterable PM (filterable PM is a surrogate for non-mercury HAP metals) for the natural gas-fired Auxiliary Boilers (identified as EPNs AUX-BOILl and AUX-BOIL2) and the Propane Vaporizers (identified as EPNs PROP-VAPI and PROP-VAP2). These facilities shall comply with all applicable requirements of 30 TAC Chapter 113, 30 TAC Chapter 116, and the EPA regulations on National Emission Standards for Hazardous Air Pollutants for Source Categories in 40 CFR Part 63, promulgated for:

A. 

### Applicable General Provisions, Subpart A; and

B. Federal Clean Air Act Section 112(g), case-by-case MACT detennination.

RECORDKEEPING REOUIREMENTS

44. The following records shall be kept at the plant for the life of the pennit. All records required in this permit shall be made available at the request of personnel from the TCEQ, the EPA, or any air pollution control agency with jurisdiction.

A. 

### A copy of this pennit.

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD-TX-I138 Page 24

B. Permit application dated May 19, 2008 and subsequent representations submitted to the TCEQ prior to pennit issuance.

C. A complete copy of the testing reports and records of the initial air emissions perfonnance testing completed pursuant to the Initial Demonstration of Compliance.

D. Required stack sampling results or other air emissions testing (other than CEMS or COMS data) that may be conducted on units authorized under this permit after the date of issuance of this peJmit.

E. The written SS plan required by Special Condition No. 14.A.

45. The following records shall be kept for a minimum of five years after collection and shall be made immediately available upon request to representatives of the TCEQ, the EPA, or any local air pollution control program having jurisdiction. Records shall be legible and maintained in an orderly mauner. The following records shall be maintained:



### A. Continuous emission monitoring data for opacity, S02, NO" CO, Hg, NH3, and diluent gases, O 2 or C02, from CEMS to demonstrate compliance with the emission rates listed in the MAERT and perfonnance standards listed in this pennit for pollutants that are monitored by CEMS or COMS. Data retention at intervals less than one hour is not required. Records must identifY the times when emissions data have been excluded from the calculation of perfonnance standards because of start -up, shutdown, maintenance, and malfunction along with the justification for excluding data. Records should also identifY factors used in calculations that are used to demonstrate compliance with emissions limits and perfonnance standards.

B. Files of all CEMS or COMS quality assurance measures including calibration checks, adjustments and maintenance performed on these systems.

C. 

### Written, ce11ified petroleum coke analysis, to include HHV, for all petroleum coke received from each petroleum coke supplier, to show compliance of the as-fired fuel with the sulfur and trace metal concentration limits of this pennit, and written certified analysis provided by natural gas and diesel fuel suppliers to show compliance with the sulfur content limitations of this permit.

D. Average petroleum coke feed rate to the CFB Boilers in pounds per hour and the conesponding average heat input (HHV) in MMBtu!hr, based upon an average over each

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-I138 Page 25

calendar month

..
E. Ammonia, limestone, and lime feed rates established during a successful initial performance test to fulfill the requirements of Special Condition Nos. 12 and 13.

F. Hours of operation of the emergency generators, fire water pumps, boiler feed water pumps, propane vaporizers, and auxiliary boilers to show compliance with the hourly operating limitations of this pelmit.

G. The amount of fuel received for storage in EPNs TNK-FWMAlN, TNK -EGl, TNK -EG2, TNK-FWBl, TNK-FWB2, TNK-FWB3, TNK-FWB4, TNK-BFWPl, TNK-BFWP2, TNK

- BFWP3, and TNK -BFWP4 and the consecutive 12-month total of fuel received for each storage tank to show compliance with the throughput requirements of this permit.

H. Records of cleaning and maintenance performed on abatement equipment, including records of replacement maintenance performed on baghouses. A log should be kept with descriptions of the activity performed, any parts or subassemblies replaced, and the time period over which the cleaning or maintenance was performed.



### I. Records required to show compliance with 40 CFR Part 60, Subparts Db and III, including daily average S02 removal efficiency, baghouse performance monitoring, and records of required reporting.



### J. Records of all venting of the anhydrous ammonia storage tanks to show compliance with Special Condition No. 20D.

K. Records of personnel training related to anhydrous ammonia injection operations and emergency response planning, including names of trainers and trainees, dates oftraining, and material covered, to show compliance with Special Condition No. 20F.



### 1. Records of audio, olfactory, and visual checks for ammonia leaks and repairs to show compliance with Special Condition No. 21.

M. Records, including dates performed, of road maintenance for dust control to show compliance with Special Condition No. 23.

REPORTING

### SPECIAL CONDITIONS Pennit Numbers 85013, HAP48, and PSD-TX-I138 Page 26

46. The holder of this pennit shall submit to the TCEQ Corpus Christi Regional Office quarterly
or semiannual reports of excess emissions and monitoring systems perfonnance, as described in 40 CFR 

### § 60.7(c), for each emission unit which is required to be continuously monitored pursuant to 40 CFR Part 60. In addition, these reports shall identify:

A. Any emissions of continuously monitored CO, ammonia, and mercury in excess of any of the limits of this pennit and monitoring systems performance, following the fonnat of 40 CFR 

### § 60.7(c);

B. The pollutant, emission rates, and test dates of any stack emission tests conducted during the reporting period which is in excess of any of the limits of this pennit.

47. Within one year after initial start-up of the first CFB, the holder of this pennit shall submit a copy of the SS plan identified in Special Condition No. 14.A. to the TCEQ Air Permits Division in Austin and the U.S. EPA Region 6 Air Pennits Section, 1445 Ross Avenue, Dallas, Texas 75202-2733.

AS-BUILT INFORMATION

48. The holder of this pennit shall submit to the TCEQ Corpus Christi Regional Office and the TCEQ Air Permits Division change pages to the permit application reflective of the final plans and engineering specifications on the CFB Boilers, auxiliary boilers, emergency engines, and other sources, including their respective control equipment, no later than 30 days before initial start-up of the CFB Boilers. This infonnation shall include:

A. 

### All TCEQ Tables in the pennit application, updated with manufacturer and other specified data.

B. Revised plot plans and equipment drawings as required to reflect the constructed facility.

C. Identification of any maximum inputs of raw materials for the as-built facility, and any diesel fuel sulfur or engine manufacturer's emission specification that is lower than the values represented in the pennit application and used for calculating or establishing emissions. Accompanying this infonnation shall be a request for pennit alteration. The TCEQ may alter the pennit special conditions and MAERT to reflect any such reduction in emissions. Increases in allowable emission rates shall require authorization before construction begins. OPTIMIZATION STUDIES

### SPECIAL CONDITIONS Permit Numbers 85013, HAP48, and PSD-TX-1138 Page 27



### 49. Within 60 days after completing the first annual compliance sampling required by Special Condition No. 37, the holder of this permit shall submit a request to adjust the performance standards for the control of H 2 S0 4 , HCI, HF, Hg, VOC, and front half and total PMIPM IO 

### identified in Special Condition No. lIB to reflect the results of the sampling of these compounds conducted to that date, with appropriate consideration given for data variability. The adjustment on a pollutant-by-pollutant basis to the performance standard for the control of H2S04, HCI, HF, Hg, VOC, or front half and total PMlPM IO 

### shall only be required if the average of the sampling for any such pollutant is 50 percent or less of the cun'ently permitted value. At a minimum, this submittal shall include the Initial Demonstration of Compliance sampling required by this permit and the first annual compliance sampling required by Special Condition No. 37.

Dated

-------.. 

### Attachment A 

### Permit Numbers 85013 and PSD- TX-1138 Non-Mercury Metal Concentrations in Petroleum Coke and Emission Performance Standards



### M

.. . .. .

. 

### aXlmum Performance Standard Constituent

. 

### Concentration (ppmw) (lbIMMBtu)

Arsenic 14.25 4.82E-05 Cadmium 3 1.0lE-05 Bervllium 2.25 7.61E-06 Lead 18 6.09E-05 Chromium 98.13 3.32E-04

Conner 5.25 1.78E-05 Man!!anese 945 3.20E-03

Selenium 397.5 l.34E-03

Silicon 25.5 8.62E-05 Aluminum 69 2.33E-04 Iron 375 1.27E-03 Calcium 28.5 9.64E-05 Sodium 97.5 3.30E-04 Potassium 42 1.42E-04 Titanium 1.5 5.07E-06 Ma!!nesium 9 3.04E-05 Nickel 880.5 2.98E-03 Vanadium 42000 1.42E-02 ..



### Dated.

______ _EMISSION SOURCES

- MAXIMUM ALLOWABLE EMISSION RATES

Permit Numbers 85013, HAP48, and PSD-TX-I 138

This table lists the maximum allowable emission rates and all sources of air contaminants on the applicant's property covered by this permit. The emission rates shown are those derived from information submitted as part of the application for permit and are the maximum rates allowed for these facilities. Any proposed increase in emission rates may require an application for a modification of the facilities covered by this permit.

AIR CONTANUNANTS DATA

Emission Source Air Contaminant Emission Rates •• Point No. (1) Name (2) Name (3) Ib/hr TPY'

CFBI and 2 CFB Boiler 1 NO x (4) 308 944 3,080 MMBtn/hr S02 (4) 714 1,160 (Normal operations S02 (start-up) (4) 4,910 including planned 

## co (4) 339 1,349 start-ups/shutdowns) VOC 15.4 67.5 PMlPM lO (filterable) 33.9 148 PMlPM lO (total) 77 337 H 2 SO 4 14 61 H 2 S0 4 (start-up) 316 NH3 (4) 16 35 Hg (4) 0.0062 0.0077 HCl 13.6 12 HCl (statt-up) 136 HF 1.2 1.1 HF (start-up) 12 Pb 0.020 0.013Penn it Numbers 85013, HAP48, and PSD-TX-1138 Page 2

EMISSION SOURCES

- MAXIMUM ALLOWABLE EMISSION RATES

Am CONTAMINANTS DATA
Emission Source Air Contaminant Emission Rates 

## **
Point No. (1) Name (2) Name (3) Ib/hr TPY*

CPBI and 2 CPB Boiler 2 NO x (4) 308 944 3,080 MMBtulhr S02 (4) 714 1,160 (Normal operations S02 (start-up) (4) 4,910 including planned CO (4) 339 1,349 start-ups/shutdowns) VOC 15.4 67.5 PMIPM IO (filterable) 33.9 148 PMlPM IO (total) 77 337 H 2 SO 4 14 61 H 2 S0 4**(st~rt-up)** 316 NH3 (4) 16 35 Hg(4) 0.0062 0.0077 HCI 13.6 12 HCI (start-up) 136 HP 1.2 1.1 HF (start-up) 12 Pb 0.020 0.013

CPB3 and4 CPB Boiler 3 NO x (4) 308 944 3,080 MMBtulhr S02 (4) 714 1,160 (Normal operations S02 (start-up) (4) 4,910 including planned CO (4) 339 1,349 start-ups/shutdowns) VOC 15.4 67.5 PMlPM IO (filterable) 33.9 148 PMlPM IO (total) 77 337 H 2 SO 4 14 61 H 2 S0 4 (start-up) 316 NH3 (4) 16 35 Hg(4) 0.0062 0.0077 HOI 13.6 12 HCI (start-up) 136 HF 1.2 1.1 HF (start-up) 12 Pb 0.020 0.013PennitNumbers 85013, HAP48, and PSD-TX-1138 Page 3

EMISSION SOURCES

- MAXIMUM ALLOWABLE EMISSION RATES

Am CONTAMINANTS DATA
Emission Source Air Contaminant Emission Rates ** Point No. (1) Name (2) Name (3) Ib/hr TPY*

CFB3 and 4 CFB Boiler 4 NO x (4) 308 944 3,080 MMBtu/hr S02 (4) 714 1,160 (Normal operations S02 (statt-up) (4) 4,910 including planned CO (4) 339 1,349 start-ups/shutdowns) VOC 15.4 67.5 PMIPM IO (filterable) 33.9 148 PMlPM IO (total) 77 337 H 2 SO 4 14 61 H 2 S0 4 (start-up) 316 NH, (4) 16 35 Hg(4) 0.0062 0.0077 HCI 13.6 12 HCI (start-up) 136 HF 1.2 l.l HF (start-up) 12 Pb 0.020 0.013

AUX-BOIL1 Auxiliary Boiler NO x (5) 6.3 7.9 for Units 1 and 2 NO x (start-up) (6) 18 180 MMBtu/hr CO (5) 7.5 9.4 (Nonnaloperations CO (start-up) (6) 75 including planned PM IO 1.4 1.7 start-ups/shutdowns) VOC 1.0 1.3 S02 0.12 0.15

AUX-BOIL2 Auxiliary Boiler NO x (5) 6.3 7.9 for Units 3 and 4 NO x (statt-up) (6) 18 180 MMBtulhr CO (5) 7.5 9.4 (Nonnaloperations CO (start-up) (6) 75 including planned PM IO 1.4 1.7 statt-ups/shutdowns) VOC 1.0 1.3 S02 0.12 0.15Penn it Numbers 85013, HAP48, and PSD-TX-I138 Page 4

EMISSION SOURCES

- MAXIMUM ALLOW ABLE EMISSION RATES

Am CONTAMINANTS DATA
Emission Source Air Contaminant Emission Rates •• Point No. (1) Name (2) Name (3) Iblhr TPY·

PROP-VAPI Propane Vaporizer NO x 1.6 2.0 for Units I and 2 CO 

### 1.3 1.6 16 MMBtulhr PM IO 0.12 0.15 VOC 0.14 0.17 S02 0.04 0.05

PROP-VAP2 Propane Vaporizer NO x 1.6 2.0 for Units 3 and 4 CO 

### 1.3 1.6 16 MMBtulhr PM IO 0.12 0.15 VOC 0.14 0.17 S02 0.04 0.05

SILO-FA I Fly Ash Silo No. 1 PMlPM,o 0.31 1.4

SILO-FA2 Fly Ash Silo No.2 PMlPM IO 0.31 1.4

SILO-FA3 Fly Ash Silo No.3 PMlPM IO 0.31 1.4

SILO-FA4 Fly Ash Silo No.4 PMlPM IO 0.31 1.4

SILO-BAI Bed Ash Silo No.1 PMlPM IO 0.24 1.0

SILO-BA2 Bed Ash Silo No.2 PMlPM IO 0.24 1.0

SILO-BA3 Bed Ash Silo No.3 PMlPM IO 0.24 1.0

SILO-BA4 Bed Ash Silo No.4 PMlPM IO 0.24 1.0

SILO-COKE! Coke Silo No.1 PMlPM IO 1.4

SILO-COKE2 Coke Silo No.2 PMlPM IO 1.4
SILO-COKEI, Coke Silos Nos 1 

### PM/PM IO 6.2

SILO-COKE2 and 2 (7)Penn it Numbers 85013, HAP48, and PSO-TX-1138 Page 5

EMISSION SOURCES

- MAXIMUM ALLOWABLE EMISSION RATES

AIR CONTAMINANTS DATA
Emission Source Ail' Contaminant Emission Rates •• Point No. (1) Name (2) Name (3) Ib/hr TPY'

SILO-COKE3 Coke Silo No.3 PMlPM IO 1.4

SILO-COKE4 Coke Silo No.4 PMlPM IO 1.4
SILO-COKE3, Coke Silos Nos. 3 PMlPM IO 6.2

SILO-COKE4 and 4 (7)

SILO-COKES Coke Silo No.5 PM/PM IO 1.4

SILO-COKE6 Coke Silo No.6 PMlPM IO 1.4
SILO-COKES, Coke Silos Nos. 5 PMlPM IO 6.2

SILO-COKE6 and 6 (7)

SILO-COKE7 Coke Silo No.7 PMlPM IO 1.4

SILO-COKE8 Coke Silo No.8 PM/PM IO 1.4
SILO-COKE7, Coke Silos Nos. 7 PMlPM IO 6.2

SILO-COKE8 and 8 (7)

SILO-LMSTI Limestone Bunker No. I PM/PM IO 0.07 0.10

SILO-LMST2 Limestone Bunker No.2 PMlPM IO 0.07 0.10

SILO-LMST3 Limestone Bunker No.3 PMlPM IO 0.07 0.10

SILO-LMST4 Limestone Bunker No.4 PMlPM IO 0.07 0.10

SILO-ACII Carbon Silo for ACI PMlPM IO 0.14 0.21 No. I

SILO-ACI2 Carbon Silo for ACI PMlPM IO 0.14 0.21 No.2

SILO-ACI3 Carbon Silo for ACI PM/PM IO 0.14 0.21 No.3Permit Numbers 85013, HAP48, and PSD-TX-1138 Page 6

EMISSION SOURCES

- MAXIMUM ALLOW ABLE EMISSION RATES

AIR CONTAMINANTS DATA
Emission Source Air Contaminant Emission Rates 

## **
Point No. (1) Name (2) Name (3) Ih/hr TPY*

SILO-ACI4 Carbon Silo for ACI PMlPM IO 0.14 0.21 No.4

SILO-LIME 1 Lime Silo No.1 

### PM/PM IO 0.14 0.21

SILO-LIME2 Lime Silo No.2 PMlPM IO 0.14 0.21

SILO-LIME3 Lime Silo No.3 PMlPM IO 0.14 0.21

SILO-LIME4 Lime Silo No.4 PMlPM IO 0.14 0.21

SILO-LIMES Lime Silo No.5 PMlPM IO 0.14 0.21

SILO-LIME6 Lime Silo No.6 

### PM/PM IO 0.14 0.21

SILO-LIME7 Lime Silo No. 7 PMlPM IO 0.14 0.21

SILO-LIME8 Lime Silo No.8 PMlPM IO 0.14 0.21

BIN-SANDI Unit 1 Sand Day Bin PMlPM IO 0.043 0.064

BIN-SAND2 Unit 2 Sand Day Bin PMlPM IO 0.043 0.064

BIN-SAND3 Unit 3 Sand Day Bin PMlPM IO 0.043 0.064

BIN-SAND4 Unit 4 Sand Day Bin PMlPM IO 0.043 0.064

WT-LIME Water Treatment PMlPM IO 0.086 0.13 Lime Silo

WT-SODA Water Treatment PM/PM IO 0.086 0.13 Soda Ash Silo

CTWRI Cooling Tower No.1 PM 12.0 52.6
PM IO 0.29 1.29Pennit Numbers 85013, HAP48, and PSD-TX-I138 Page 7

EMISSION SOURCES

- MAXIMUM ALLOW ABLE EMISSION RATES

Am CONTAMINANTS DATA
Emission Source Air Contaminant Emission Rates ** Point No. (1) Name (2) Name (3) Ih/hr TPY*

CTWR2 Cooling Tower No.2 PM 12.0 52.6 PM IO 0.29 1.29

ENG-EGJ Diesel Engine NO x 24.3 6.1 Emergency CO 13.3 3.3 Generator I PM IO 0.61 0.15 1,600 kW VOC 1.5 0.37 S02 0.93 0.23 H 2 SO 4 0.070 0,0]8

ENG-EG2 Diesel Engine NO x 24.30 6.10 Emergency CO 13.30 3.30 Generator 2 PM IO 0.61 0.15 1,600 kW VOC 1.46 0.37 S02 0.93 0.23 H 2 SO 4 0.070 0.018

ENG-FWMAIN Main Fire Water Pump NO x 2.38 0.60 Diesel Engine CO 2.06 0.52 360-horsepower PM IO 0.12 0.03 VOC 0.89 0.22 S02 0.14 0.04 H 2 SO 4 0,0] 0.003

ENG-FWBPI Fire Water NO x 0.66 0.17 Booster Pump I CO 0.57 0.14 Diesel Engine PM IO 0.03 0.01 100-horsepower VOC 0.25 0.06 S02 0.04 0.01 H 2 SO 4 0.003 0.001Pennit Numbers 85013, HAP48, and PSD- TX-1138 Page 8

EMISSION SOURCES

- MAXIMUM ALLOW ABLE EMISSION RATES

Am CONTAMINANTS DATA
Emission Source Air Contaminant Emission Rates ** Point No. (1) Name (2) Name (3) Ib/hr TPY*

ENG-FWBP2 Fire Water NO x 0.66 0.17 Booster Pump 2 CO 0.57 0.14 Diesel Engine PM IO 0.03 0.01 I DO-horsepower VOC 0.25 0.06 S02 0.04 0.01 H 2 SO 4 0.003 0.001

ENG-FWBP3 Fire Water NO x 0.66 0.17 Booster Pump 3 CO 0.57 0.14 Diesel Engine PM IO 0.03 0.01 I DO-horsepower VOC 0.25 0.06 S02 0.04 

# om H 2 SO 4 0.003 0.001

ENG-FWBP4 Fire Water NO x 0.66 0.17 Booster Pump 4 CO 0.57 0.14 Diesel Engine PM IO 0.03 0.01 100 horsepower VOC 0.25 0.06 S02 0.04 0.01 H 2 SO 4 0.003 0.001

ENG-BFWPI Boiler Feed Water (BFW) NO x 13.23 3.31 Pump I CO 11.46 2.87 Diesel Engine PM IO 0.66 0.17 2,000 horsepower VOC 4.94 1.24 S02 0.80 0.20 H 2 SO 4 0.06 0.016

ENG-BFWP2 BFW Pump 2 NO x 13.23 3.31 Diesel Engine CO 11.46 2.87 2,000 horsepower PM IO 0.66 0.17 VOC 4.94 1.24 S02 0.80 0.20 H 2 SO 4 0.06 0.016Permit Numbers 85013, HAP48, and PSD-TX-I 138 Page 9

EMISSION SOURCES

- MAXIMUM ALLOWABLE EMISSION RATES

AIR CONTAMINANTS DATA
Emission Source Air Contaminant Emission Rates •• Point No. (1) Name (2) Name (3) Ih/hr TPY'

ENG-BFWP3 BFW Pump 3 NO x 13.23 3.31 Diesel Engine CO 11.46 2.87 2,000 horsepower PM IO 0.66 0.17 VOC 4.94 1.24 S02 0.80 0.20 H 2 SO 4 0.06 0.016

ENG-BFWP4 BFWPump4 NO x 13.23 3.31 Diesel Engine CO 11.46 2.87 2,000-horsepower PM IO 0.66 0.17 VOC 4.94 1.24 S02 0.80 0.20 H 2 SO 4 0.06 0.016

TNK-FWMAIN Diesel Fuel Tank for VOC 0.0104 0.0002 Main Fire Water Pump Engine

TNK-EGI Diesel Fuel Tank for VOC 0.0104 0.0001 Emergency Generator I

TNK-EG2 Diesel Fuel Tank for VOC 0.0104 0.0001 Emergency Generator 2

TNK-FWBI Diesel Fuel Tank for Fire VOC 0.0104 0.0003 Water Booster Pump 1 Engine

TNK-FWB2 Diesel Fuel Tank for Fire VOC 0.0104 0.0003 Water Booster Pump 2 Engine

TNK-FWB3 Diesel Fuel Tank for Fire VOC 0.0104 0.0003 Water Booster Pump 3 EnginePennit Numbers 85013, HAP48, and PSD-TX-1138 Page 10

EMISSION SOURCES

- MAXIMUM ALLOW ABLE EMISSION RATES

AIR CONTAMINANTS DATA
Emission Source Air Contaminant Emission Rates •• Point No. (1) Name (2) Name (3) Ib/hr TPY'

TNK-FWB4 Diesel Fuel Tank for Fire VOC 0.0104 0.0003 Water Booster Pump 4 Engine

TNK-BFWPI Diesel Fuel Tank for VOC 0.0104 0.0004 BFW Pump I Engine

TNK-BFWP2 Diesel Fuel Tank for VOC 0.0104 0.0004 BFW Pump 2 Engine

TNK-BFWP3 Diesel Fuel Tank for VOC 0.0104 0.0004 BFW Pump 3 Engine

TNK-BFWP4 Diesel FuelTank for VOC 0.0104 0.0004 BFW Pump 4 Engine

TNK-ACID Acid Storage Tank H 2 SO 4 0.16 0.0032

TNK-BASE Base Storage Tank NaOH 0.069 0.0014

FUG-NH3A Fugitives: Ammonia NH3 (8) 0.10 0.45

FUG-NH3B Fugitives: Ammonia NHJ (8) 0.10 0.45

FUG-NG Fugitives: Natural Gas VOC (8) 0.19 0.84

FUG-PROPI Fugitives: Propane VOC (8) 0.41 1.80

FUG-PROP2 Fugitives: Propane VOC (8) 0.41 1.80Permit Numbers 85013, HAP48, and PSD-TX-I 138 Page II

EMISSION SOURCES

- MAXIMUM ALLOWABLE EMISSION RATES
(I) Emission point identification

- either specific equipment designation or emission point number from plot plan. (2) Specific point source name. For fugitive sources use area name or fugitive source name. (3) NO x total oxides of nitrogen

(4) (5) (6) (7) (8)



# •

•• SO, sulfur dioxide VOC volatile organic compounds as defined in Title 30 Texas Administrative Code § 101.1 PM particulate matter, suspended in the atmosphere, including PM IO • PM IO particulate matter equal to or less than 10 microns in diameter. Where PM is not listed, it shall be assumed that no PM greater than 10 microns is emitted. NH3 ammonia CO carbon monoxide H,S04 sulfuric acid mist Pb lead HCI hydrogen chloride HF hydrogen fluoride Hg mercury Compliance with the hourly emission limit is based on a three-hour block average of the CEMS data. Hourly limit applies when auxiliary boiler is operating at or above 25 percent load. Hourly limit applies when auxiliary boiler is operating below 25 percent load, and during statt-up and shutdown. Only one of the two paired coke silo fabric filters operates at the same time. Fugitives emission rate is an estimate and compliance is demonstrated by meeting the requirements of the applicable special conditions and permit application representations.

For combustion sources and storage tanks, compliance with annual emission limits is based on a rolling 12-month period. For material handling sources, compliance with annual emission limits is based on applicable Special Conditions and pelmit application representations.
Except as otherwise specified in special conditions, emission rates are based on and the facilities are limited by the following maximum operating schedule:**Hrs/day~ Days/week~7~**  Weeks/year 52 or Hrs/yr 8,760**Dated._~~~~~~~_**P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A N EW C OMBINED C YCLE C OGENERATION U NIT AT THE LBEC LBEC, LLC

Zephyr Environmental Corporation

010303 

## APPENDIX B
GHG PSD APPLICABILITY FLOWCHART

– NEW SOURCES

###  

## Appendix B. GHG Applicability Flow Chart – New Sources (On or after July 1, 2011)

 	

	
 
	
		 	
	



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