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 11 Richmond,Suite3S0 t. 713-35 1-6700 

Houston Texas 77042 ( 7 13·351 ·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 johnupchurch@chase-power. com or by telephone at (713) 351-6701 . 

S;"?7~ iip'h""h Managing Partner ~-~, Chase Power Development LLC. 

Enclosure 

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

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, 2011 
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT AT THE LBEC

LBEC, LLC

Zephyr Environmental Corporation 010303

i

TABLE OF CONTENTS

1.0 INTRODUCTION.............................................................................................................1

FORM PI-1 GENERAL APPLICATION .......................................................................................4

2.0 PROJECT SCOPE........................................................................................................14

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

2.2 CFB Boilers .........................................................................................................17

2.3 Auxiliary Boilers ...................................................................................................17

2.4 Propane Vaporizers .............................................................................................18

2.5 Diesel-Fired Emergency Equipment.....................................................................18

2.6 Electrical Equipment Insulated with Sulfur Hexafluoride (SF6)..............................18

PROCESS FLOW DIAGRAM....................................................................................................19

PLOT PLAN..............................................................................................................................20

AREA MAP ...............................................................................................................................21

3.0 GHG EMISSION CALCULATIONS................................................................................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 Equipment Insulated with SF6............................24

4.0 PREVENTION OF SIGNIFICANT DETERIORATION APPLICABILITY .........................33

TCEQ PSD NETTING TABLES ................................................................................................34

5.0 BEST AVAILABLE CONTROL TECHNOLOGY (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 SF6 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 CO2 PIPELINES AND POTENTIAL GEOLOGIC STORAGE SITES IN 

TEXAS ..........................................................................................................................53
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT AT THE LBEC

LBEC, LLC

Zephyr Environmental Corporation 010303

ii

TABLE 5-1 ................................................................................................................................55

6.0 OTHER PSD REQUIREMENTS....................................................................................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 SOURCES
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT AT THE LBEC

LBEC, LLC

Zephyr Environmental Corporation 010303

1

1.0 INTRODUCTION

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 Corpus Christi, Texas. The facility, with an 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 Deterioration (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, 

following 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 process before the State Office 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 address 

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). 

According 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 Tailoring 

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 LBEC pursuant to the Tailoring Rule turns on whether 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.
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT 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 action 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 further 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 permit 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, on December 13, 2010, EPA issued 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 had 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 

permits 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 “good 
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT 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 final rule 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, Chase 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. Despite having a signed 

PSD permit, Las Brisas remains practically unable to build Las Brisas. Due to EPA’s December 

30, 2010 issuance of the interim rule partially disapproving Texas’s PSD SIP and imposing a 

FIP on Texas. If Petitioner’s permit is considered issued after January 2, 2011, as EPA 

maintains, the permit was 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 interim rule, Texas would not have been divested of its authority to issue PSD permits, 

and Las Brisas would have clear authority to build LBEC 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 EPAPSD 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 until EPA promulgates this [interim 

final] rule, Texas sources will not have available a permitting authority to process their PSD permit applications and as a result, 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 Texas until at least the December 1, 2011 

deadline for submitting a revised SIP. See United States v. Cinergy Corp., 623 F.3d 455, 458 (7th Cir. 2010) (Posner, J.).
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT AT THE LBEC

LBEC, LLC

Zephyr Environmental Corporation 010303

4

FORM PI-1 

GENERAL APPLICATION
TCEQ – 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 Information (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.com

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

2 9

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 Facility (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 (SO2):

Carbon Monoxide (CO):

Nitrogen Oxides (NOx):

Particulate Matter (PM):

PM 10 microns or less (PM10):

PM 2.5 microns or less (PM2.5):

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

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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/A
Texas 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

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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 _____ 7 9

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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 requirements 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

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XII. 

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.tceq.texas.gov/agency/delin/index.html. 

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 __ 
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2.0 PROJECT SCOPE

2.1 PLANT DESIGN CONSIDERATIONS

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 new 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 liquidlike 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. Even though the combustion temperature 

of a CFB boiler is lower than a PC boiler, the circulation of hot particles provides efficient heat 

transfer 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). 
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CFB boilers, 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 operating 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, bituminous coal, began operation in June 2009. Considering 

that only one supercritical CFB unit is in operation and only a small amount of operational 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 SO2 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. 

The PKE plant was permitted at the following emission limits: 200 mg/m3

n @ 6% O2, dry for 

both NOx and SO2.

3

 This equates to 0.17 lb/MMBtu for both NOx and SO2, utilizing the Fd

Factor for Bituminous Coal of 9,780 dscf/MMBtu4

. 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 SO2 emission limit of 0.17 lb/MMBtu is approximately 2 times higher than 

the annual average SO2 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 to 

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 SO2 reduction) 

are introduced into the boiler together. However the combustor and cyclones 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 projects 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 facilities 

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 smaller 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 source 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.
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

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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 scale 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 (IGCC) 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 power 

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, high 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. Historically 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 CO2 Capture”, Stanford University 

Global Climate Change & Energy Project Research 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 $2.88 billion5

 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 is 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.pdf (last visited 10/27/2011)
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

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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 billion6 ($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 Project. 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 billion7

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 project costs. There is however, a clear indication that IGCC construction 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 is 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, while little 

operational data exist to support the use of supercritical technology.

2.2 CFB BOILERS

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 fourth CFB Boilers (EPN CFB-3 

and CFB-4) will feed steam to a second single steam turbine-generator.

2.3 AUXILIARY BOILERS

Two nominally rated 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 of 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 13, 2009

http://www.tenaska.com/newsItem.aspx?id=62
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(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 PROP ANE VAP ORIZERS

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. 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 DIESEL-FIRED EMERGENCY EQUIPMENT

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 serve 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 pumps 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 hours per year for the purpose of maintenance 

checks and readiness testing.8

2.6 ELECTRICAL EQUIPMENT INSULATED WITH SULFUR HEXAFLUORIDE (SF6)

The generator circuit breakers associated with the proposed CFB units will be insulated with 

SF6. SF6, 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 SF6 make it an efficient electrical insulator; it is used for electrical insulation, arc 

quenching, and current interruption in high-voltage electrical equipment. SF6 is only used in 

sealed and safe systems which under normal circumstances do not leak gas. The capacity of 

the generator circuit breakers associated with the proposed unit will be approximately 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 breaker due to lack of “quenching and cooling” SF6 gas.

 8 40 CFR §60.4211(e)
• 

• 

• 

...----- ------ Water Treatment (Typical for 2 Units) I 

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 

------, (Typical 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 ar-t up 

AUX-BOIL1 

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 Number 

Las Brisas Energy Center, LLC 

Corpus Christi, Nueces County, TX 

Figure 2-1 

Process Flow Diagram 

404 Camp Craft Rd. 

Austin, TX 78746 ....... JDC 

Las Brisas Exhibit 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 400FT 

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 

3-2 
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3.0 GHG EMISSION CALCULATIONS

3.1 GHG EMISSIONS FROM CFB BOILERS

CO2 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

 CH4 and N2O emission calculations are calculated using 

the emission factors (kg/MMBtu) for petroleum coke from Table C-2 of the Mandatory 

Greenhouse Gas Reporting Rules.10 The global warming potential factors used to calculate 

CO2e emissions are based on Table A-1 of Mandatory Greenhouse Gas Reporting Rules.11

CO2 emissions are generated from the use of the sorbent (crushed limestone) in the SO2

removal system in the CFB boilers in the following manner:

• CO2 is released from the reaction of CaCO3 with SO2 by the following reaction: CaCO3 + 

SO2  CaSO3 + CO2

• The remaining CaCO3 in the limestone is decomposed due to the heat in the boiler by 

the following reaction: CaCO3  CaO + CO2

• The MgCO3 in the limestone is decomposed due to the heat in the boiler by the following 

reaction: MgCO3  MgO+ CO2.

• Organic carbon compounds in the limestone are oxidized to produced H2O and CO2.

CO2 emissions from the use of CaCO3 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 because equation G-5 is

based on the total amount of CaCO3 used and equation G-6 is based only on the amount of 

CaCO3 stoichiometrically required based on the amount of SO2 removed. An excess of 

limestone will be added to the CFB boilers to promote the reaction and high removal of SO2 in 

the CFB bed. Using equation G-5 accounts to both the CO2 released from the reaction of 

CaCO3 with SO2 and the CO2 released from the excess CaCO3 in the limestone decomposing in 

the boilers. Equation G-5 provides as follows:12

SECO2 = W CaCO3 x Fu x MWCO2/MWCaCO3 (Eq. G-5)

Where: 

SECO2 = CO2 emitted from sorbent, tons/yr. 

WCaCO3 = CaCO3 used, tons/yr

Fu = 1.0, the calcium to sulfur stoichiometric ratio.

 9 Default CO2 Emission Factors and High Heat Values for Various Types of Fuel, 40 C.F.R. 98, Subpt. C, Tbl. C-1

10 Default CH4 and N2O 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 CO2 Emissions
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MW CO2 = Molecular weight of carbon dioxide, 44.0 lb/lb-mole. 

MW CaCO3 = Molecular weight of CaCO3, 100.0 lb/lb-mole.

CO2 emissions from the decomposition of the MgCO3 in the limestone are based on the 

stoichiometric ratio of one mole of CO2 generated for each mole of MgCO3 added to the boiler. 

This is consistent with the GHG reporting calculation method for Cement Production in 40 CFR 

98, Subpart H, except that it is based on the amount of MgCO3 input rather than the amount of 

MgO produced.

CO2 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 EMISSIONS FROM AUXILIARY BOILERS

CO2 emissions from the natural-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 CH4 and N2O emissions from the auxiliary boilers are calculated using the emission 

factors (kg/MMBtu) for natural gas from Table C-2 of the Mandatory Greenhouse Gas Reporting 

Rules.14 The global warming potential factors used to calculate CO2e emissions are based on 

Table A-1 of Mandatory Greenhouse Gas Reporting Rules.15

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

3.3 GHG EMISSIONS FROM PROP ANE VAP ORIZERS

CO2 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 CH4 and N2O 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 global warming potential factors used to calculate CO2e emissions are based on 

Table A-1 of Mandatory Greenhouse Gas Reporting Rules.18

Calculations of GHG emissions from the propane vaporizers are presented on Table 3-4.

 13 Default CO2 Emission Factors and High Heat Values for Various Types of Fuel, 40 C.F.R. 98, Subpt. C, Tbl. C-1

14 Default CH4 and N2O 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 CO2 Emission Factors and High Heat Values for Various Types of Fuel, 40 C.F.R. 98, Subpt. C, Tbl. C-1

17 Default CH4 and N2O 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, Tbl. A-1.
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT AT THE LBEC

LBEC, LLC

Zephyr Environmental Corporation 010303

24

3.4 GHG EMISSIONS FROM NATURAL GAS PIPING FUGITIVES

GHG emissions from natural gas piping components are based on emission factors from Table 

W-1A of the Mandatory Greenhouse Gas Reporting Rules.19 The concentrations of CH4 and 

CO2 in the natural gas are based on a typical natural gas analysis. The global warming 

potential factors used to calculate CO2e emissions are based on Table A-1 of Mandatory 

Greenhouse Gas Reporting Rules.20

Calculations of GHG emissions from the natural gas piping components are presented on Table 

3-5.

3.5 GHG EMISSIONS FROM DIESEL FIRED EMERGENCY ENGINES

CO2 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 Mandatory Greenhouse Gas 

Reporting Rules.21 CH4 and N2O 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 global warming potential factors used to 

calculate CO2e emissions are based on Table A-1 of Mandatory Greenhouse Gas Reporting 

Rules.23

Calculations of GHG emissions from the emergency engines are presented on Table 3-6.

3.6 GHG EMISSIONS FROM ELECTRICAL EQUIPMENT INSULATED WITH SF6

SF6 emissions from the new generator circuit breakers associated with the proposed unit are 

calculated using a predicted SF6 annual leak rate of 0.5% by weight. The global warming 

potential factors used to calculate CO2e emissions are based on Table A-1 of Mandatory 

Greenhouse Gas Reporting Rules.24

Calculations of GHG emissions from electric equipment insulated with SF6 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 CO2 Emission Factors and High Heat Values for Various Types of Fuel, 40 C.F.R. 98, Subpt. C, Tbl. C-1

22 Default CH4 and N2O 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 Mass 

Emissions CO2e

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

TOTAL 12,945,757 13,080,273

10/28/2011
Table 3-2

GHG Emission Calculations - CFB Boilers

Las Brisas Energy Center LLC

GHG Potential To Emit Emissions From Coke Fired CFB Boilers

GHG Emissions from fuel firing

EPN Fuel Use1 Annual Operation

Maximum Heat Input1 Pollutant Emission Factor GHG Mass Emissions CO2e

(MMBtu/hr coke) (hr/yr) (MMBtu/yr) (kg/MMBtu)2 (tpy) (tpy)

CO2 102.04 3,034,765 1 3,034,765.1

3,080 8760 26,980,800 CH4 1.1E-02 327.15 21 6,870.2

N2O 1.6E-03 47.59 310 14,751.5

Totals 3,035,139.8 3,056,386.8

Note

1. 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 unit

EPN Maximum Heat 

Input

Limestone 

Used4 CaCO3 Used4 MgCO3 Used4 CO2 From CaCO3 5

CO2 From 

MgCO3 6 Total CO2 

(MMBtu/yr) TPY (tpy) (tpy) (tpy) (tpy)4 (tpy) 

CFB-1 through CFB-4 (each unit) 26,980,800 424,041 388,888 14,333 186,578 9,231 3,110 198,918 1 Note

4. Calculation of Limestone, CaCO3 , MgCO 3 Usage

Fuel Sulfur = 6.7 wt% (annual average)

Fuel HHV = 13,800 Btu/lb

Fuel Sulfur Input = 4.86 lb S/MMBtu

Potential SO2 output = 9.71 lb SO2/MMBtu

Ca/S Ratio = 1.90 (an excess of limestone is added to promote the reaction and high removal of SO2 in the CFB bed)

CaCO 3 Usage = 28.8 lb CaCO3/MMBtu

Avg. CaCO 3 wt% in Limestone = 91.7% (From TCEQ PSD Application)

Avg. MgCO 3 wt% in Limestone = 3.4% (From TCEQ PSD Application)

Limestone Usage = 31.43 lb limestone/MMBtu

MgCO3 Usage = 1.06 lb MgCO3/MMBtu

Global Warming 

Potential3

CFB-1 through CFB-4 

(each unit)

Glob

Warm

Poten

CO2 From 

Organic Carbon 

in Limestone7 

(tpy)

Page 1 of 2 
Table 3-2

GHG Emission Calculations - CFB Boilers

Las Brisas Energy Center LLC

5. SE CO2 = W CaCO3 * Fu *MW CO2 /MW CaCO3 + (40 CFR Part 75 Appendix G, Equation G-5) 

where, SECO2 = CO2 emitted from sorbent, ton/yr

WCaCO3 = CaCO3 used, ton/yr

Fu = 1.0, the calcium to sulfur stoichiometric ratioMWCO2 = molecular weight of CO2 = 44

MWCaCO3 = molecular weight of CaCO3 = 100

6. CO 2 liberated from MgCO3 

MgCO 3 => MgO + CO 2CO 2 ton/yr = MgCO3 ton 2000 lb lbmole MgCO3 1 lbmole CO2 44 lb CO2 ton

yr ton 68.32 lb MgCO3 1 lbmole MgCO3 lbmole CO2 2000 lb

7. CO2 Emissions from Organic Carbon Content of Limestone

Organic Carbon Content of Limestone = 0.2 wt% default value from 40 CFR 98, Subpart H, Equation H-5CO 2 ton/yr = Limestone ton 2000 lb 0.002 lb C lbmole C 1 lbmole CO2 44 lb CO2 ton

yr ton lb limestone 12 lb C 1 lbmole C lbmole CO2 2000 lb

TOTAL GHG Emissions

EPN Pollutant GHG Mass Emissions CO2e

(tpy) (tpy)

CO2 3,221,343 3,233,683.2

CH4 327 6,870.2

N2O 48 14,751.5

Totals 3,221,717.7 3,255,304.8

MSS Emissions Comparison

Operation Mode Fuel Type Fuel Use 8 Emission factor 9 Emission factor 9 Emission factor 9 Emissions Emissions Emissions

MMBtu/hr CO - lb/MMBtu CH4 - lb/MMBtu N2O - lb/MMBtu CO -lb/hr CH4 - lb/hr N2O - lb/hr

Normal Operation coke 3080.0 224.96 0.0243 0.0035 692,869 75 11

coke 770.0 224.96 0.0243 0.0035 173,217 19 3

natural gas 426.0 116.89 0.00220 0.00022 49,794 1 0

223,011 20 3

Normal operation emissions are larger.Note

8. 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-up

TOTAL

CFB-1 through CFB-4 

(each unit)

Page 2 of 2 
Table 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 Use1 HHV of Fuel1 Maximum 

Heat Input1 Pollutant Emission 

Factor

GHG Mass 

Emissions CO2e

(MMscf/yr) (MMBtu/MMscf) (MMBtu/yr) (kg/MMBtu)2 (tpy) (tpy)

CO2 53.02 26,310.99 1 26,311.0

453.8 992 450,192 CH4 1.0E-03 0.50 21 10.4

N2O 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 

Potential3

AUX-BOIL1 and 

AUX-BOIL2

10/28/2011
Table 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 Use1 HHV of Fuel 1 Maximum 

Heat Input1 Pollutant Emission 

Factor

GHG Mass 

Emissions CO2e

(MMscf/yr) (MMBtu/MMscf) (MMBtu/yr) (kg/MMBtu)2 (tpy) (tpy)

CO2 61.46 2,710.44 1 2,710.4

15.745 2541 40,008 CH4 3.0E-03 0.13 21 2.8

N2O 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 

Potential3

PROP-VAP1 and 

PROP-VAP1

10/28/2011
Table 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 CO2

2 Methane3 Total

Type State Factor1 (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 Potential4 1 21

CO2e 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 CO2 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 CO2 lbmole 44.01 lb CO2 8760 hr ton = 0.12 ton/yr

hr * valve scf gas 385.5 scf lbmole yr 2000 lb

10/28/2011
Table 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 CO2e

(MMBtu/hr) (kg/MMBtu)1 (tpy) (tpy)

CO2 73.96 144.8 1 144.8

17.8 CH4 3.0E-03 0.01 21 0.1

N2O 6.0E-04 0.00 310 0.4

Totals 144.82 145.3

CO2 73.96 22.6 1 22.6

ENG-FWMAIN 2.8 CH4 3.0E-03 0.00 21 0.0

N2O 6.0E-04 0.000 310 0.1

Totals 22.58 22.7

CO2 73.96 6.3 1 6.3

0.8 CH4 3.0E-03 0.0 21 0.0

N2O 6.0E-04 0.0 310 0.0

Totals 6.27 6.3

CO2 73.96 125.4 1 125.4

15.4 CH4 3.0E-03 0.0 21 0.1

N2O 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 

Potential2

ENG-EG1 & 2 (each 

unit)

ENG-FWB1 to 4 

(each unit)

ENG-BFWP1 to 4 

(each unit)

10/28/2011
Table 3-7

GHG Emission Calculations - Electrical Equipment Insulated With SF6

Corpus Christi, Nueces County, Texas

Assumptions

New insulated circuit breaker SF6 capacity 570 lb

Estimated annual SF6 leak rate 0.5% by weight

Estimated annual SF6 mass emission rate 0.001425 ton/yr

Global Warming Potential1 23,900

Estimated annual CO2e 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. 

10/28/2011
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT AT THE LBEC

LBEC, LLC

Zephyr Environmental Corporation 010303

33

4.0 PREVENTION OF SIGNIFICANT DETERIORATION APPLICABILITY

Because the project emissions increase of GHG is greater than 75,000 ton/yr of CO2e, 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 APPLICABILITY FLOWCHART – NEW 

SOURCES” from the PSD and Title V Permitting Guidance for Greenhouse Gases.
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT AT THE LBEC

LBEC, LLC

Zephyr Environmental Corporation 010303

34

TCEQ PSD NETTING TABLES
TAULE IF 

AIR Q UALln' APPLICATION SU PPL ~IENT 

Penn it No.: 85013, PSD-TX-1 138, HAP48 IApplicatioli Submittal Date: 

Company Las Brisas Encrg}' Center LI.C 

RN: RN 105520779 Facility Locntion: Co rpus Christi 

City Corpus CllTisli Cm1llty: Nueces 

Permit Uni t J.D.: 011 units Penni! Name: Electric Generation Facility 

Permit Activit\': o Ilew t·1ajor Source D /·\odiflcatloo 

Project or Process Dcscri )Iion: Authorize new CFB boil ers and ancill ary equipment 

Complete fol' ~II flollutnllis wilh a IJroject POLLUTANTS 

emission incl'ease. Ozone CO SO, 1'1\ I 

NOx I VOC 

Nonatlainment? (yes or no) I 

Ex isting site PTE (Ipy) This form for GIIG only Proposed project ncr~'as"s (tpy from 2fi 

Is Ihe existing site a major source? If nOl, is Ihe project a 

major source by itself? (ycs or no) Yes 

lfsite is major, is project increase signil1cant? (yes or no) I I I 

I filCHing required, estimated start of constmction: 1111112 

5 years prior to start of construction: 11 /2/07 Contempomneous 

estimated start of opcrntion: 111117 Period 

Nct contemporaneous change, including proposed project, 

from Table 3F (tpy) 

FNSR applicable? (yes or 110) 

I. Other PSD pollutants 

2. Nonallailllllcnimajor SOllrce is defined in Table 1 in 30 TAC 11 6. 12( 11 ) by pollulmll and coullty. PSD thresholds 

are fOllnd in ·IO eFR §S1.1 66(b)(J). 

3. Sum of proposed emissions minus baseline emissions, increases only. Nonatlainmcnt thresholds arc found in 

Table 1 in 30 TAC 11 6. 12( 11 ) and PSD th resholds ill 40 CFR §5 I.1 GG(b)(23). 

GIIG 

No 

0 

12,945,757 

Yes 

12,945,757 

Yes 

Date 

COle 

No 

0 

13,080)73 

Yes 

13,080)73 

Yes 
TABLE 2F

PROJECT EMISSION INCREASE

Pollutant(1): GHG Permit: Electric Generation FacilityBaseline Period: N/A to N/A

A B

Affected or Modified Facilities(2) Permit 

No.

Actual 

Emission

s(3)

Baseline 

Emissions

(4)

Proposed 

Emissions

(5)

Projected 

Actual 

Emissions

Difference 

(A-B)(6)

Correction(7) 

In

FIN EPN

1 CFB-1 CFB-1 85013 0 0 3,221,718 3,221,718 

2 CFB-2 CFB-2 85013 0 0 3,221,718 3,221,718 

3 CFB-3 CFB-3 85013 0 0 3,221,718 3,221,718 

4 CFB-4 CFB-4 85013 0 0 3,221,718 3,221,718 

5 AUX-BOIL1 AUX-BOIL1 85013 0 0 26,312 26,312 6 AUX-BOIL2 AUX-BOIL2 85013 0 0 26,312 26,312 7 PRO-VAP1 PRO-VAP1 85013 0 0 2,711 2,711 

8 PRO-VAP2 PRO-VAP2 85013 0 0 2,711 2,711 

9 ENG-EG1-1 ENG-EG1-1 85013 0 0 145 145 

10 ENG-EG1-2 ENG-EG1-2 85013 0 0 145 145 

11 ENG-FWMAIN ENG-FWMAIN 85013 0 0 23 23 

12 ENG-FWB1 ENG-FWB1 85013 0 0 6 6 13 ENG-FWB2 ENG-FWB2 85013 0 0 6 6 14 ENG-FWB3 ENG-FWB3 85013 0 0 6 6 

15 ENG-FWB4 ENG-FWB4 85013 0 0 6 6 16 ENG-BFWP1 ENG-BFWP1 85013 0 0 125 125 17 ENG-BFWP2 ENG-BFWP2 85013 0 0 125 125 18 ENG-BFWP3 ENG-BFWP3 85013 0 0 125 125 19 ENG-BFWP4 ENG-BFWP4 85013 0 0 125 125 20 FUG-NG FUG-NG 85013 0 0 3 3 

21 FUG-SF6 FUG-SF6 85013 0 0 0.0014 0.0014 

Total 1

1. 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 as any 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 the Table 2F 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 and basis 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 2F

PROJECT EMISSION INCREASE

Pollutant(1): CO2e Permit: Electric Generation Facility

Baseline Period: N/A to N/A

A B

Affected or Modified Facilities(2) Permit 

No.

Actual 

Emission

s(3)

Baseline 

Emissions

(4)

Proposed 

Emissions

(5)

Projected 

Actual 

Emissions

Difference 

(A-B)(6)

Correction(7) 

FIN EPN

1 CFB-1 CFB-1 85013 0 0 3,255,305 3,255,305 

2 CFB-2 CFB-2 85013 0 0 3,255,305 3,255,305 3 CFB-3 CFB-3 85013 0 0 3,255,305 3,255,305 4 CFB-4 CFB-4 85013 0 0 3,255,305 3,255,305 5 AUX-BOIL1 AUX-BOIL1 85013 0 0 26,337 26,337 6 AUX-BOIL2 AUX-BOIL2 85013 0 0 26,337 26,337 7 PRO-VAP1 PRO-VAP1 85013 0 0 2,721 2,721 

8 PRO-VAP2 PRO-VAP2 85013 0 0 2,721 2,721 

9 ENG-EG1-1 ENG-EG1-1 85013 0 0 145 145 10 ENG-EG1-2 ENG-EG1-2 85013 0 0 145 145 11 ENG-FWMAIN ENG-FWMAIN 85013 0 0 23 23 12 ENG-FWB1 ENG-FWB1 85013 0 0 6 6 13 ENG-FWB2 ENG-FWB2 85013 0 0 6 6 14 ENG-FWB3 ENG-FWB3 85013 0 0 6 6 15 ENG-FWB4 ENG-FWB4 85013 0 0 6 6 16 ENG-BFWP1 ENG-BFWP1 85013 0 0 126 126 17 ENG-BFWP2 ENG-BFWP2 85013 0 0 126 126 18 ENG-BFWP3 ENG-BFWP3 85013 0 0 126 126 19 ENG-BFWP4 ENG-BFWP4 85013 0 0 126 126 20 FUG-NG FUG-NG 85013 0 0 61 61 21 FUG-SF6 FUG-SF6 85013 0 0 34 34 

Total 

1. 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 as any 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 the Table 2F 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 and basis 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.
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT AT THE LBEC

LBEC, LLC

Zephyr Environmental Corporation 010303

38

5.0 BEST AVAILABLE CONTROL TECHNOLOGY (BACT)

5.1 DEFINITION 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 reduction 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 that 

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 

thereof, 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, work 

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 examine the highest-ranked (“top”) option and

the 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 impacts 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 selected 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. 2011).
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT AT THE LBEC

LBEC, LLC

Zephyr Environmental Corporation 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 CFB BOILERS

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 gas 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 Brisas 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 unit’s efficiency is its “heat 

rate,” which is expressed as the number 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 heat 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 

Power Annual 2009 at 49, Table 5.3, available at 

CFB Boiler Energy Efficiency

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

epa_sum.html.

CO2 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 CO2 generated 

from combustion, as CO2 is the essential product of the chemical reaction between the fuel and 

the oxygen in which it burns, not a byproduct caused by imperfect combustion. As such, there 

is no technology available that can effectively reduce CO2 generation by adjusting the 

conditions in which combustion takes place. 

The only effective means to reduce the amount of CO2 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 technologies, so that as much of the energy content of the 

fuel as possible goes into generating power.
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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. Furthermore, 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 the 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 then 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 

influence 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 heating 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 system thus adding another element of efficiency to the overall system.

Boiler Feed Water Pumps

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. Electric 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. 
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Regenerative Air Heaters

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 recover 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 maximizing 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 panels that make up the shell of the boilers and associated convective 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 fouling 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 the 

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 boiler 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, 
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to achieve increased thermal cycle efficiencies, a reheat cycle is employed at Las Brisas. This 

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, the lower the exhaust pressure, the higher the overall turbine efficiency. For highefficiency units, such as Las Brisas, the exhaust steam is wet or saturated under vacuum 

conditions. This is accomplished by the use of a condenser 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, which 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 of 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 the 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, natural 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 

permitting 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 project design 
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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 coke 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 consumer, 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 initiate 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 boilers 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 options 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 emerging carbon capture and storage 

(CCS) technologies generally consist of processes that concentrate CO2 from combustion 

process flue gas, and then inject it into geologic formations such as oil and gas reservoirs, 

unmineable coal seams, and underground saline formations. Emerging CO2 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 CO2, thereby reducing the need 

for a post-combustion CO2 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 fuel-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 

CO2 capture technology and related costs:

 27 EPA, PSD and Title V Permitting Guidance For Greenhouse Gases, March 2011, at 48-49.
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“...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 slipstream applications, and 

no definitive analysis exists as to the actual costs for a full-scale capture plant. 

Preliminary analysis conducted at NETL indicates that CO2 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 CO2 from this flue gas stream is challenging for several reasons: 

• CO2 is present at dilute concentrations (13-15 volume percent in coalfired systems29

• Trace impurities (particulate matter, sulfur dioxide, nitrogen oxides) in the 

flue gas can degrade sorbents and reduce the effectiveness of certain 

CO2 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 CO2 from atmospheric pressure to 

pipeline pressure (about 2,000 psia) represents a large auxiliary power 

load on the overall power plant system...”30

If CO2 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 CO2 trapping mechanisms within 

the formation, including dissolution in brine, reactions with minerals to form solid carbonates, 

and/or adsorption in porous rock. The DOE-NETL describes the geologic formations that could 

potentially serve as CO2 storage sites as follows:

“Geologic carbon dioxide (CO2) storage involves the injection of supercritical CO2 into 

deep geologic formations (injection zones) overlain by competent 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=UTF8&client=default_frontend&site=default_collection&proxystylesheet=default_frontend&oe=ISO-8859-1 (last visited 

Sept. 28, 2011).

29 CO2 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=UTF8&client=default_frontend&site=default_collection&proxystylesheet=default_frontend&oe=ISO-8859-1 (last visited 

Sept. 28, 2011).
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geologic traps that will prevent the CO2 from escaping. Current research and field 

studies are focused on developing better understanding of 11 major types of geologic 

storage reservoir classes, each having their own unique opportunities and challenges. 

Understanding these different storage classes provides insight into how the systems 

influence fluids flow within these systems today, and how CO2 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, 

carbonate 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 CO2 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 CO2 Capture, Compression, and Transport

Though amine absorption technology for CO2 capture has been utilized in the petroleum refining 

and natural gas processing 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 boilers used 

for power generation, which have considerably larger flow volumes and considerably lower CO2

concentrations than other processes. The Obama Administration’s Interagency Task Force on 

Carbon Capture and Storage confirms this in its recently completed report on the current status 

of development of CCS systems:

“Current technologies could be used to capture CO2 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 CO2 capture 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).
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In its current CCS research program plans, the DOE-NETL confirms that commercial CO2

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) Develop technologies that can separate, capture, transport, and store CO2 using

either direct or indirect systems that result in a less than 10 percent increase in the 

cost of energy by 2015;

(2) Develop technologies that will support industries’ ability to predict CO2 storage 

capacity in geologic formations to within ±30 percent by 2015; 

(3) Develop technologies to demonstrate that 99 percent of injected CO2 remains in 

the injection zones by 2015;

(4) Complete 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 several decades.”33

To corroborate that commercial availability of CO2 capture technology for large-scale power 

plant projects will not occur for several more years, Alstom, one of the major developers of 

commercial CO2 capture technology using post-combustion amine absorption, post-combustion 

chilled ammonia absorption, and oxy-combustion, states on its web site that its CO2 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 CO2 emissions generated by a project of the size of Las Brisas. 

The “large-scale demonstration project” to which Alstom refers on its web site would be able to 

capture 1 million tons of CO2 per year, an order of magnitude less than the CO2 generated by 

the Las Brisas project.

Even if it is assumed that CO2 capture and compression could feasibly be achieved for the 

proposed project, the high-volume CO2 stream generated would need to be transported to a 

facility capable of storing it. Potential geologic storage sites in Texas, Louisiana, and 

Mississippi to which CO2 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 CO2 transport pipeline is 

uncertain due to the uncertainty of identifying a site(s) that is suitable for large-scale, long-term 

CO2 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 CO2 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).
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The closest site that is currently being field-tested to demonstrate its capacity for large-scale 

geological storage of CO2 is the Southwest Regional Partnership on Carbon Sequestration’s 

(SWP) SACROC test site, which is located in Scurry County, Texas approximately 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 CO2 generated by the proposed 

project, a very long and sizable pipeline would need to be constructed to transport the large 

volume of high-pressure CO2 from the plant to the storage facility, thereby rendering 

implementation of a CO2 transport system infeasible.

5.2.2.2 CO2 Storage

Even if it is assumed that CO2 capture and compression could feasibly be achieved for the 

proposed project and that the CO2 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 formations, CO2

trapping mechanisms within formations (including dissolution in brine, reactions with minerals to 

form solid carbonates, and/or adsorption in porous rock), and potential environmental impacts

resulting from injection of CO2 into the formations. Potential environmental impacts resulting 

from CO2 injection that still require assessment before CCS technology can be considered 

feasible include:

• Uncertainty concerning the significance of dissolution of CO2 into brine,

• Risks of brine displacement resulting from large-scale CO2 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 CO2, including the possibility for damage to 

the biosphere, underground drinking water sources, and/or surface water,36

• Potential effects on wildlife.

and

Potentially suitable storage sites, including EOR sites and saline formations, exist in Texas, 

Louisiana, and Mississippi. In fact, sites with such recognized potential for some geological 

storage of CO2 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, the closest site that is currently being field-tested to demonstrate its 

capacity for geological storage of the volume of CO2 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 CO2 generated by the proposed project has yet to be fully demonstrated.

 36 Id.
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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 infeasible, 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 

of that option is not necessary for this application. 

5.2.5 Step 5: Select BACT

Las Brisas proposes as BACT for this project, to utilize energy efficient 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

design net heat rate and then calculated a compliance 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% Boiler 

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:
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• A 5% design margin reflecting the CFB boiler provider’s performance guarantee

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

year period

• 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 1.28 ton CO2e/MW-hr (2.55 lb CO2e/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. Calculation of the net heat rate and the 

equivalent ton CO2e/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-fuelfired 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 Brisas’ 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 biomass 

to be located in Rogers City, Michigan. The Permit to Construct, issued on July 29, 2011 listed 

a GHG BACT limit of 2.1 lb CO2e/kW-hr, gross output, 12-month rolling average. Note that the 

BACT limit is based on gross electrical output and not net electrical 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 CO2 emission factor for a subbituminous 

coal/petroleum coke/bio-mass mixture of 221.5 lb CO2/MMBtu versus the emission factor for 

100% petroleum coke combustion of 225.0 lb CO2/MMBtu. For direct comparison purposes, the 

“design” net heat rate 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 SF6 INSULATED ELECTRICAL EQUIP 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 SF6 technology with leak detection to limit 

fugitive emissions. In comparison to older SF6 circuit breakers, modern breakers are designed 

as a totally enclosed-pressure system with far lower potential for SF6 emissions. In addition, the 

effectiveness of leak-tight closed systems can be enhanced by equipping them with a density 
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alarm that provides a warning when 10% of the SF6 (by weight) has escaped. The use of an 

alarm identifies potential leak problems before the bulk of the SF6 has escaped, 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 SF6 as the dielectric material in the breakers. Potential alternatives to SF6 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 SF6.

37 

5.3.2 Step 2: Eliminate Technically Infeasible Options

According to the report NTIS Technical Note 1425, SF6 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 

SF6-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 equipment.” Therefore there 

are currently no technically feasible options besides use of SF6.

5.3.3 Step 3: Rank Remaining Control Technologies

The use of state-of-the-art SF6 technology with leak detection to limit fugitive emissions is the

highest ranked control technology that is technically feasible for this application.

5.3.4 Step 4: Evaluate Most Effective Controls and Document Results

Energy, environmental, or economic impacts were not addressed in this analysis because the 

use of alternative, non-greenhouse-gas substance for SF6 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 enclosedpressure SF6 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 SF6, NIST Technical Note 1425, Nov.1997.

38 Id. at 28 – 29.
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Institute (ANSI) C37.013 standard for high voltage circuit breakers.

39 The proposed 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 SF6 emissions 

problems to light before a substantial portion of the SF6 escapes. The lockout prevents any 

operation of the breaker due to lack of “quenching and cooling” SF6 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 SF6 emissions will be calculated according to the mass balance 

approach in Equation DD-1 of Subpart DD.

5.4 BACT FOR AUXILIARY BOILERS AND PROP ANE VAPORIZERS

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 will 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 limited 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

proposes as BACT for this project, 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 

determinations 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 2011 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-gasfired 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.
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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 EMERGENCY ENGINES

The proposed project will include installation of high efficiency diesel-fired emergency 

generators, fire water pump engines, 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 engines for purpose of maintenance checks and readiness 

testing will be limited to 100 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 engines 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 BACT for GHG 

emissions.

 41 See 40 C.F.R. Pt. 60, Subpt. IIII.
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MAP OF EXISTING CO2 PIPELINES AND POTENTIAL GEOLOGIC STORAGE SITES IN 

TEXAS
Pipelines for 

naturally 

occuring CO, 

NEW 

MEXICO 

SACROC 

Southwest 

Partnership 

NM Tech 

u -, uO 200 miles 

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

o 300 kilometers 

Source: Base drawing from University 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 

CO2-EOR production and potential 

o Major oil plays 
Base 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 

Potential2

CO2e

Btu/kW-hr (HHV, Net) (MMBtu/yr) (kg/MMBtu)1 (ton/MWhr) (ton/MWhr)

10,607.9 10.61 Limestone 

calcination CO2 6.69 0.078 1 0.07821

Pet Coke 

combustion CO2 102.0400 1.193 1 1.19316

Pet Coke 

combustion CH4 0.0110 0.00006 21 0.00123

Pet Coke 

combustion N2O 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

10/28/2011
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6.0 OTHER PSD REQUIREMENTS

6.1 IMPACTS ANALYSIS

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 CO2 or GHGs.42

An impacts analysis for non-GHG emissions was submitted with the application for TCEQ 

Permit No. 85013/PSD-TX-1138/HAP-48. 

6.2 GHG PRECONSTRUCTION MONITORING

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 ADDITIONAL IMP ACTS ANALYSIS

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 PSD 

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 the 

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.
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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 

PSD 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 the 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 

emissions 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 

GHGs.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. 
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7.0 GHG MONITORING

CO2 emissions from the CFB Boilers 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 

CO2 emission monitoring system in accordance with the requirements of 40 CFR 

§75.10(a)(3)(i). Emissions of CH4 and N2O 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

CO2, CH4, and N2O 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.

CH4 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.

SF6 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.
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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 .. 

NOx 0.10 Hourly 

NOx 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 Method3 (RM) testing: 

... .. . 

Performance Standard Compliance 

Pollutant' (lbIMMBtu)2 Demonstration 

Period. 

PMlPM,o (fiont- 0.011 3-hour average 

half catch) 

PM/PMIO total 0.0254 3-hour average 

VOC 0.0050 3-hour average 

H2SO4 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 NOx _ 

SO, 

CO -

PM -

nitrogen oxides 

sulfur dioxide 

carbon monoxide 

particulate matter 

PMlO -

VOC -

H,S04 -

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 PMlPMlO including back-half(condensibles) catch of sampling train. 

12. In the event that a CEMS for NOx 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) NOx - 0.035IbIMMBtu; 

(2) CO - 50 ppmvd, at 3 percent O2; 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) NOx - 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) NOx - 0.10 IbIMMBtu; 

(2) CO - 100 ppmvd, at 3 percent O2; 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, H2S04, HCI, HF, PM, PMJQ, NH3, and Hg. Diluents to be measured 

include O2 or carbon dioxide (C02), 

(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 NOx 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 NOx, CO, and filterable PM perfonnance 

standards of Special Condition No. 16A and the hourly NOx 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 NOx 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 O2, 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 NHJ; 

(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, PMlO (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 NOx, 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 NOx, 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 NOx, 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 ofNH3 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 H2S04, HCI, HF, VOC, and total PMlPMIO 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 PMlPMIO 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 PMIO (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 H2S04, 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, O2 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 H2S04, HCI, HF, Hg, VOC, and front half and total 

PMIPMIO 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 PMlPMIO 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 NOx (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 

PMlPMlO (filterable) 33.9 148 

PMlPMlO (total) 77 337 

H2SO4 14 61 

H2S04 (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 0.013 
Penn 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 NOx (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 

PMIPMIO (filterable) 33.9 148 

PMlPMIO (total) 77 337 

H2SO4 14 61 

H2S04 (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 NOx (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 

PMlPMIO (filterable) 33.9 148 

PMlPMIO (total) 77 337 

H2SO4 14 61 

H2S04 (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 0.013 
PennitNumbers 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 NOx (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 

PMIPMIO (filterable) 33.9 148 

PMlPMIO (total) 77 337 

H2SO4 14 61 

H2S04 (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 NOx (5) 6.3 7.9 

for Units 1 and 2 NOx (start-up) (6) 18 

180 MMBtu/hr CO (5) 7.5 9.4 

(Nonnaloperations CO (start-up) (6) 75 

including planned PMIO 1.4 1.7 

start-ups/shutdowns) VOC 1.0 1.3 

S02 0.12 0.15 

AUX-BOIL2 Auxiliary Boiler NOx (5) 6.3 7.9 

for Units 3 and 4 NOx (statt-up) (6) 18 

180 MMBtulhr CO (5) 7.5 9.4 

(Nonnaloperations CO (start-up) (6) 75 

including planned PMIO 1.4 1.7 

statt-ups/shutdowns) VOC 1.0 1.3 

S02 0.12 0.15 
Penn 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 NOx 1.6 2.0 

for Units I and 2 CO 1.3 1.6 

16 MMBtulhr PMIO 0.12 0.15 

VOC 0.14 0.17 

S02 0.04 0.05 

PROP-VAP2 Propane Vaporizer NOx 1.6 2.0 

for Units 3 and 4 CO 1.3 1.6 

16 MMBtulhr PMIO 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 PMlPMIO 0.31 1.4 

SILO-FA3 Fly Ash Silo No.3 PMlPMIO 0.31 1.4 

SILO-FA4 Fly Ash Silo No.4 PMlPMIO 0.31 1.4 

SILO-BAI Bed Ash Silo No.1 PMlPMIO 0.24 1.0 

SILO-BA2 Bed Ash Silo No.2 PMlPMIO 0.24 1.0 

SILO-BA3 Bed Ash Silo No.3 PMlPMIO 0.24 1.0 

SILO-BA4 Bed Ash Silo No.4 PMlPMIO 0.24 1.0 

SILO-COKE! Coke Silo No.1 PMlPMIO 1.4 

SILO-COKE2 Coke Silo No.2 PMlPMIO 1.4 

SILO-COKEI, Coke Silos Nos 1 PM/PMIO 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 PMlPMIO 1.4 

SILO-COKE4 Coke Silo No.4 PMlPMIO 1.4 

SILO-COKE3, Coke Silos Nos. 3 PMlPMIO 6.2 

SILO-COKE4 and 4 (7) 

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

SILO-COKE6 Coke Silo No.6 PMlPMIO 1.4 

SILO-COKES, Coke Silos Nos. 5 PMlPMIO 6.2 

SILO-COKE6 and 6 (7) 

SILO-COKE7 Coke Silo No.7 PMlPMIO 1.4 

SILO-COKE8 Coke Silo No.8 PM/PMIO 1.4 

SILO-COKE7, Coke Silos Nos. 7 PMlPMIO 6.2 

SILO-COKE8 and 8 (7) 

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

SILO-LMST2 Limestone Bunker No.2 PMlPMIO 0.07 0.10 

SILO-LMST3 Limestone Bunker No.3 PMlPMIO 0.07 0.10 

SILO-LMST4 Limestone Bunker No.4 PMlPMIO 0.07 0.10 

SILO-ACII Carbon Silo for ACI PMlPMIO 0.14 0.21 

No. I 

SILO-ACI2 Carbon Silo for ACI PMlPMIO 0.14 0.21 

No.2 

SILO-ACI3 Carbon Silo for ACI PM/PMIO 0.14 0.21 

No.3 
Permit 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 PMlPMIO 0.14 0.21 

No.4 

SILO-LIME 1 Lime Silo No.1 PM/PMIO 0.14 0.21 

SILO-LIME2 Lime Silo No.2 PMlPMIO 0.14 0.21 

SILO-LIME3 Lime Silo No.3 PMlPMIO 0.14 0.21 

SILO-LIME4 Lime Silo No.4 PMlPMIO 0.14 0.21 

SILO-LIMES Lime Silo No.5 PMlPMIO 0.14 0.21 

SILO-LIME6 Lime Silo No.6 PM/PMIO 0.14 0.21 

SILO-LIME7 Lime Silo No. 7 PMlPMIO 0.14 0.21 

SILO-LIME8 Lime Silo No.8 PMlPMIO 0.14 0.21 

BIN-SANDI Unit 1 Sand Day Bin PMlPMIO 0.043 0.064 

BIN-SAND2 Unit 2 Sand Day Bin PMlPMIO 0.043 0.064 

BIN-SAND3 Unit 3 Sand Day Bin PMlPMIO 0.043 0.064 

BIN-SAND4 Unit 4 Sand Day Bin PMlPMIO 0.043 0.064 

WT-LIME Water Treatment PMlPMIO 0.086 0.13 

Lime Silo 

WT-SODA Water Treatment PM/PMIO 0.086 0.13 

Soda Ash Silo 

CTWRI Cooling Tower No.1 PM 12.0 52.6 

PMIO 0.29 1.29 
Pennit 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 

PMIO 0.29 1.29 

ENG-EGJ Diesel Engine NOx 24.3 6.1 

Emergency CO 13.3 3.3 

Generator I PMIO 0.61 0.15 

1,600 kW VOC 1.5 0.37 

S02 0.93 0.23 

H2SO4 0.070 0,0]8 

ENG-EG2 Diesel Engine NOx 24.30 6.10 

Emergency CO 13.30 3.30 

Generator 2 PMIO 0.61 0.15 

1,600 kW VOC 1.46 0.37 

S02 0.93 0.23 

H2SO4 0.070 0.018 

ENG-FWMAIN Main Fire Water Pump NOx 2.38 0.60 

Diesel Engine CO 2.06 0.52 

360-horsepower PMIO 0.12 0.03 

VOC 0.89 0.22 

S02 0.14 0.04 

H2SO4 0,0] 0.003 

ENG-FWBPI Fire Water NOx 0.66 0.17 

Booster Pump I CO 0.57 0.14 

Diesel Engine PMIO 0.03 0.01 

100-horsepower VOC 0.25 0.06 

S02 0.04 0.01 

H2SO4 0.003 0.001 
Pennit 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 NOx 0.66 0.17 

Booster Pump 2 CO 0.57 0.14 

Diesel Engine PMIO 0.03 0.01 

I DO-horsepower VOC 0.25 0.06 

S02 0.04 0.01 

H2SO4 0.003 0.001 

ENG-FWBP3 Fire Water NOx 0.66 0.17 

Booster Pump 3 CO 0.57 0.14 

Diesel Engine PMIO 0.03 0.01 

I DO-horsepower VOC 0.25 0.06 

S02 0.04 om 

H2SO4 0.003 0.001 

ENG-FWBP4 Fire Water NOx 0.66 0.17 

Booster Pump 4 CO 0.57 0.14 

Diesel Engine PMIO 0.03 0.01 

100 horsepower VOC 0.25 0.06 

S02 0.04 0.01 

H2SO4 0.003 0.001 

ENG-BFWPI Boiler Feed Water (BFW) NOx 13.23 3.31 

Pump I CO 11.46 2.87 

Diesel Engine PMIO 0.66 0.17 

2,000 horsepower VOC 4.94 1.24 

S02 0.80 0.20 

H2SO4 0.06 0.016 

ENG-BFWP2 BFW Pump 2 NOx 13.23 3.31 

Diesel Engine CO 11.46 2.87 

2,000 horsepower PMIO 0.66 0.17 

VOC 4.94 1.24 

S02 0.80 0.20 

H2SO4 0.06 0.016 
Permit 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 NOx 13.23 3.31 

Diesel Engine CO 11.46 2.87 

2,000 horsepower PMIO 0.66 0.17 

VOC 4.94 1.24 

S02 0.80 0.20 

H2SO4 0.06 0.016 

ENG-BFWP4 BFWPump4 NOx 13.23 3.31 

Diesel Engine CO 11.46 2.87 

2,000-horsepower PMIO 0.66 0.17 

VOC 4.94 1.24 

S02 0.80 0.20 

H2SO4 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 

Engine 
Pennit 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 H2SO4 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 1.80 
Permit 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) NOx 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 PMIO • 

PMIO 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._~~~~~~~_ 
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A NEW COMBINED CYCLE COGENERATION UNIT 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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