VIA U.S. MAIL AND EMAIL 

Mr. Eric Massey 

Division Director, Air Quality Division 

Arizona Department of Environmental Quality 

111 0 West Washington Street 

Phoenix, Arizona 85007 

Re: Application for Regional Haze State Implementation Plan Revision 

Apache Generating Station, Arizona Electric Power Cooperative, Inc. 

Dear Director Massey: 

Arizona Electric Power Cooperative, Inc. (''AEPCO") hereby applies to the Arizona Department of 

Environmental Quality ("ADEQ'') for a revision to the State Implementation Plan ("SIP") to 

implement the proposed AEPCO "better than best available retrofit technology ("'BART")'' 

alternative that AEPCO submitted to the U.S. Environmental Protection Agency ("EPA") as a result 

of EPA's disapproval of ADEQ's Regional Haze SIP and promulgation of a Federal implementation 

Plan ("FIP") on AEPCO's Apache Generating Station. See 77 Fed. Reg. 72512 (Dec. 5, 2012). The 

purpose of this petition is to implement a resolution to AEPCO's petition for administrative 

reconsideration as agreed during a joint conference call of AEPCO, ADEQ and EPA on June 26, 

2013, and to resolve an error in calculating the NOx emission rate from Steam Unit 1 ("STl") and 

Gas Turbine 1 ("GT1 ")operating in combined cycle mode. 

Background 

As you are aware, AEPCO petitioned EPA for administrative reconsideration of the FIP on February 

2, 2013. AEPCO submitted a supplement to its petition for administrative reconsideration to EPA 

setting forth a proposed resolution that would achieve ·'better than BART" levels of visibility 

improvement more consistent with ADEQ's calculated Uniform Rate of Progress on May 29,2013. 

On June 6, 2013, EPA granted AEPCO's request for administrative reconsideration. Discussions then 

followed between AEPCO, ADEQ and EPA representatives on how best to implement the 

administrative reconsideration. ADEQ expressed a preference to adopt the AEPCO proposal as part 

of a SIP revision, likely in the form of a permit attachment that would then be submitted as a format 

SIP revision. This approach was acceptable to AEPCO and EPA. All parties recognized that public 

notice and comment will be required. 

In addition, AEPCO's engineering staff, when reviewing the emission rates for ST1 and GTJ for 

purposes of implementing the regional haze SIP, discovered an overlooked aspect of AEPCO's 

original BART submittal that has resulted in the SIP's BART rate for Units STI and GTJ when 

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the approval of the NOx BART limit for STI/GTl. Including the GTI NOx contribution results in an 

emission rate of 0.1 Jb/MMBtu NOx, well above the current BART detennination. 

Petition for SIP Revision 

Consistent with its petition for administrative reconsideration, supplement to its petition, and EPA's 

grant of that petition as supplemented, AEPCO formally petitions ADEQ to adopt the the AEPCO 

proposal in the supplement to its petition as a proposed revision to the Arizona Regional Haze SIP 

and to submit that revision to EPA for approval as the mechanism to complete EPA's 

reconsideration. As discussed, AEPCO has converted its proposal (originally in FIP fonnat) to a 

proposed new "Attachment E'' to AEPCO's Apache Generating Station Class I Air Quality Permit. A 

copy of the proposed ·'Attachment E" is attached for your consideration. AEPCO looks forward to 

working with ADEQ to finalize this proposal. 

Based on the June 26, 2013 and subsequent discussions, AEPCO understands that this new 

Attachment E would be proposed as both a conditional permit revision (e.g., one that would take 

effect upon EPA's approval as a SIP revision) and as a SIP revision. After appropriate public notice 

and comment on both actions, ADEQ would approve the conditional pennit revision and propose it 

as a SIP revision to EPA for final approval. After further notice and comment at the federal level, 

EPA would then approve or disapprove this proposal as its reconsideration action, concluding the 

reconsideration proceeding opened by its June 6, 2013 letter granting AEPCO's request for 

administrative reconsideration. If EPA approves the SIP revision, then Attachment E would become 

binding as both pa1t of the Arizona SIP and as an effective part of AEPCO's Class I Air Quality 

Penn it. lf EPA disapproved, then Attachment E would not become part of the SIP and would never 

become an effective part of AEPCO's Class I Air Quality Penn it. 

On the Unit STJ/GTl issue identified above, AEPCO petitions ADEQ to revise the BART limit for 

NOx as follows: 

• To establish NOx BART for Unit STl in stand-alone operation at 0.056 lb/MMBtu, 30 boiler 

operating day rolling average, as stated in the current BART detennination; 

• To establish NOx BART for Unit STl/GTI in combined cycle operation at 0.1 lb/MMBtu, 30 

boiler operating day rol!ing average, and 

• To establish a NOx BART limit that restricts total NOx from both stand-alone operation of 

Unit STJ and combined cycle operation of Unit STI and Unit GTJ (except in combined 

warming/drying operation) to 1205 pounds per day, 30 calendar day rolling average. 

The effect of these proposed restrictions is to maintain or improve upon the visibility improvements 

from the original BART determination for NOx/day from Steam Unit 1 and Gas Turbine 1 while 

allowing AEPCO to continue to operate units STl and GTJ in combined cycle mode at the 0.10 

lb/MMBtu rate which reflects the actual capability of the unit if the Gas Turbine I emissions are 

added back. The limit is derived as follows (using net generation values): 

DocumenL<;/Gcncration Envirmuncmal/ AIRJ AEPCO S!P Rev Cover.docx November 25, 20!3 
The 82 MW is taken from AEPCO's contract delivery obligation to its members. 111e 10,985 

Btu/kWhr represents a reasonable conservative estimate of the heat rate over the primary operating 

range of STI and GTI in combined cycle operation (the actual value can range from 10,821 to 

II, I70 Btu/kWh depending on operating conditions at the time). The proposed limit also ensures that 

the maximum impact from Units STI and GTl are always less than the original BART limit. AEPCO 

believes that this is the best way to resolve the issue caused by the oversight of not including the GTl 

emissions in the BART determination. 

AEPCO is confident that the overall proposal results in visibility impacts that are better than both the 

original regional haze SIP's BART determination and EPA's FIP BART determination due to the 

reductions in emissions achieved. 

AEPCO appreciates ADEQ's and EPA's willingness to work with AEPCO in this reconsideration of 

the December 5, 2012 FlP. We would be pleased to provide any additional technical information 

required or to discuss possible changes to the draft Attachment E language to enhance clarity for aH 

parties. Please contact me at 480-505-3927 or Michelle Freeark, AEPCO's Director of 

Environmental Services, at 520-586-5122, if you have any questions or concerns. We look forward to 

working with you. 

Sincerely, 

Eric L. Hiser 

Counsel for AEPCO 

enc 

Via Cerlified Mail- 92071900 0052 6987 6300 44 

c/ D. Whitley & M. Freeark, AEPCO w/enc 

T. Baggiore & B. Vaidyanathan, ADEQ w/enc 

C. McKaughan & C Withey, EPA Region 9 w/enc 

Region 9 Air Pennits w/enc 9207 1900 0052 6987 6300 51 

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2. Mailing Address: P.O. Box 670 

City: Benson State: Arizona ZIP: 85602 

3. Name (or names) of Owners/Principals: Patrick F. Ledger 

Phone: 520.586.5110 Fax: 520.586.5576 Email: pledger@ssw.coop 

4. Plant'Site Manager/Contact Person and Title: Apache Generation Station 

Phone: 520.384.6509 Fax: 520.384.6557 Email: mnelson@aepco.coop 

5. Plant Site Name: Apache Generation Station 

Plant Site Location/Address: 3525 N. Hwy 191 South 

City: Cochise County: Cochise ZIP: 85606 

Indian Reservation (if applicable, which one): N/A 

Latitude/Longitude, Elevation: 32"03'.768n/109" 53.588'W, 4185' ELEV 

6. Equipment Purpose: BART- Regional Haze Compliance 

7. Type of Organization: 

[Z] Corporation Individual Owner ·· Partnership Government Entity) 

Other 

8. Permit Application Basis: I,; New Source I{] Revision ··Renewal ofExisting Permit 

For renewal or modification, include existing permit number (and exp. date): 55412 07/23/2018 

Date of Commencement of Construction or Modification: 

Standard Industrial Classification Code: 4911 State Permit Class: 520.586.5110 

I certify that I have knowledge of the facts herein set forth, that the same are true, accurate and complete to the best of my 

knowledge and belief, and that all information not identified by me as confidential in nature shall be treated by ADEQ as public 

record. 1 also attest that I am in compliance with the applicable requirements of the Pcnnit and will continue to comply with such 

requirements and any futuro requirements that become effective during the life of the Permit. I will present a certification of 

compliance to ADEQ no less than annually and more frequently if Specified by ADEQ. I further state that I will assume 

responsibility for the construction, modification, or operation of the source in accordance with Arizona Administrative Code, 

Title 18, Chapter 2 and any permit issued thereof. 

9. Signature of Responsible Official of d 

10. Printed Name of Signer/Official Title: Michael D. Nelson, Director of Power Production 

Date: November 26,2013 Telephone Number: 520.384.6509 
the ADEQ standard questions. The other questions are not applicable to this revision. 

It is AEPCO's understanding that ADEQ will process this application, including the supporting 

information in the AEPCO Petition and Supplement, as a revision to the Arizona SIP and will 

then submit the package to EPA for final approval into the SIP, which would also constitute 

EPA's action on AEPCO's Petition for Administrative Reconsideration. 

An explanation of the Steam Unit 1 changes are in the cover letter to this submittal for ADEQ's 

review and consideration. AEPCO has also attached to this application a proposed Attachment E 

incorporating all BART elements under EPA guidance. This application also incorporates the 

AEPCO Petition for Administrative Reconsideration, filed with EPA on February 2, 2013, and 

the Supplement to the Petition for Administrative Reconsideration, filed with EPA on May 29, 

2013, copies of which were previously provided to ADEQ. Please let us know if you need 

additional copies of these documents. 

1. Detailed description of processes at the facility. 

This application provides for incorporating proposed revisions to "Best Available Retrofit 

Technology" (BART) previously submitted in a Petition for Administrative Reconsideration and 

a Supplement to the Petition for Administrative Reconsideration to U.S. EPA and ADEQ. This 

application is solely to change the emission limits and associated monitoring, recordkeeping and 

reporting requirements. AEPCO will submit a subsequent application to install the control 

equipment and make the actual physical modifications to the Apache Station. The proposed 

revision would accomplish the following changes: 

Steam Unit 1 

The proposed revision incorporates clarifications on when the BART limit applies to Steam Unit 

1 in stand alone operation and when it applies to Steam Unit 1 and Gas Turbine I running in 

combined operation. After discussions with EPA and ADEQ, it has been detennined that the 

BART limits apply to both standalone operation of Steam Unit 1 and combined operation of 

Steam Unit 1 and Gas Turbine 1. Emissions generated during periods when Gas Turbine 1 is 

exhausting through its own stack or exhausting through the Steam Unit 1 windbox and Steam 

Unit 1 is not firing and not producing electricity, are not counted for BART purposes. 

The proposal also corrects an error in the original CH2MHill BART submittal for Steam Unit I. 

That submittal incorrectly detem1ined that emissions from Gas Turbine 1 are not considered for 

BART pw-poses at any time.EPA and ADEQ have determined that this is not the case. As a 

result, emissions from Gas Turbine 1 need to be added to the BART determination. AEPCO does 

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the visibility impact under the prior BART limit All other SIP and BART limits remain in place. 

Stearn Unit 2 

AEPCO proposes to convert Steam Unit 2 from coal to natural gas firing on the effective date of 

the current BART determination, December 5, 2017. Converting Steam Unit 2 from coal to 

natural gas significantly reduces S02 emissions (from 0.15 lb/MMBtu, 30 boiler operating day 

average to 0.00064 lb/MMBtu, 30 boiler operating day average), reduces PM emissions (from 

O.D3 lb/MMBtu, 30 boiler operating day average to 0.01 and then 0.008 lb/MMB!u, 30 boiler 

operating day average), and results in a slight increase in NOx emissions (from 0.07 lb/MMBtu, 

30 boiler operating day average to 0.085 lb/MMBtu, 30 boiler operating day average). AEPCO 

retains the right to run Steam Unit 2 on coal in the event of a pipeline natural gas supply 

disruption caused by events such as a pipeline break or freeze-up, to ensure electric delivery to 

its customers. AEPCO would return to natural gas only firing promptly upon restoration of 

pipeline service. 

Stearn Unit 3 

AEPCO also proposes, in conjunction with the conversion of Steam Unit 2 to natural gas, to 

convert the presently-required selective catalytic reduction (SCR) control technology on Steam 

Unit 3 to selective non-catalytic reduction (SNCR). This results in an increase in the NOx 

emission rate from 0.07 lb/MMBtu to 0.23 lb/MMBtu, 30 boiler operating day average. AEPCO 

recognizes that this is a significant change. Nevetiheless, modeling supplied to EPA and ADEQ 

as part of AEPCO's Petition and Supplement demonstrates that the overall visibility impact of 

converting Steam Unit 2 to natural gas and Steam Unit 3 to SNCR still results in a net visibility 

improvement over both ADEQ's original SIP BART and the EPA FIP BART. Accordingly, 

AEPCO believes that this proposal constitutes a "better than BART" application that can be 

approved to replace the existing BART established in the Arizona regional haze SIP and the 

federal regional haze FIP. 

2. A flow diagram for all processes. 

Not applicable. 

3. Description of alternate operating scenarios, if applicable. 

AEPCO has requested an alternate operating scenario for Steam Unit 2 to allow it to burn coal in 

the event of a pipeline supply disruption. Paragraph 1 below explains the types of disruptions 

that would qualify. Paragraph 2 specifies that Steam Unit 2 would then comply with the SIP coal 

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immediately upon restoration of natural gas service, depending upon electric demand, but can be 

achieved within the 90 day period. As a practical matter, particulate matter emissions will begin 

to decline immediately upon resumption of natural gas firing, but may not achieve final natural 

gas limits until cleaning. 

1. The Permittee will not operate Steam Unit 2 on coal after December 5, 2017 except in the 

event of a supply disruption caused by natural gas supplier or transporter pipeline failure, 

freeze-up or pipeline compression failure that reduces gas volume or gas pressure below that 

necessary for Apache Generating Station gas generation. The Permittee must discontinue coal 

firing as expeditiously as possible after restoration of natural gas service at levels supporting 

continuous firing of Steam Unit 2 and in no event more than 48 hours after restoration of such 

service. 

2. During any such period of coal operation and for such period thereafter as provided in 

Section lll.E.3, the Permittee shall comply with the emission limits set forth in Condition 

Ill.B.l for PM10 and S02 and shall minimize NOx emissions by use of good combustion 

practices and not to exceed 0.37 lb/MMBtu, averaged over 30 boiler-operating days. 

3. Effective with the next boiler operating day after coal combustion ceases for NOx and S02, 

and within 90 boiler operating days after coal combustion ceases for PM10, the Permittee shall 

resume compliance with the applicable emissions limits set forth in Conditions III.B or III.D, 

as applicable. 

4. Emissions Related Information. 

Please see Appendix A, providing information for Steam Unit 1 NOx emissions. Emissions 

information for Steam Units 2 and 3 is found in the Petition for Administrative Reconsideration 

and Supplement to the Petition for Administrative Reconsideration. 

5. An explanation of any proposed exemptions from otherwise applicable 

requirements. 

See discussion under #3 above. 

6. The permittee will be required to conduct air dispersion modeling for all new 

sources and certain types of modifications to existing sources to document 

compliance with applicable ambient standards. The criteria for when modeling is required and how the modeling should be conducted are comprehensively covered 

in the Department's air dispersion modeling guidelines that are available online 

at: 

http://www.azdeg.gov/environ/air/permits/standards.html 

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AEPCO is not presently aware of any collateral emissions impacts from the proposed emissions 

controls set forth in this proposal. 

7. Applicants are requested to provide a modeling protocol prior to conducting the 

modeling .... 

AEPCO conducted modeling using the current EPA-approved visibility modeling, as set forth in 

its Supplement to the Petition for Administrative Reconsideration. 

8. A comprehensive equipment list that contains information about the make, model, 

serial number, equipment id number, date of manufacture of all process and 

control equipment. 

Not applicable. This is an application to establish the emission control technology limits. Once 

the permit and SIP limits are established, AEPCO must then complete engineering to select the 

final equipment. AEPCO is confident that there are presently available technologies that will 

meet the limits proposed herein. AEPCO will file a subsequent permit filing with ADEQ to 

provide the specific information requested in this question. 

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Attachment "E" shall become effective on the effective date of the Administrator's action 

approving it as part of the state implementation plan. 

Where multiple emission limits, standards or requirements apply to a unit, the most 

stringent limit, standard or requirement controls. 

II. Best Available Retrofit Technology for Steam Unit 1 

A. Applicability. 

1. The BART limit for Stearn Unit 1 will apply when Steam Unit I operates in standalone operation or when Steam Unit 1 and Gas Turbine 1 operate in combined cycle 

operation. 

2. The BART limit does not apply to: 

a. Gas Turbine 1 in stand-alone simple cycle operation; or 

b. Steam Unit 1 and Gas Turbine I in combined warming/drying operation when 

the Steam Turbine I burners are shut off and Steam Turbine 1 is not 

producing electricity. 

B. Best Available Retrofit Technology Limits 

[AZ RH SIP, 77 Fed. Reg. 70512, 70515 (Dec. 5, 2012)] 

1. Steam Unit 1 shall combust only pipeline natural gas. 

2. Steam Unit 1 shall not emit more than 0.00064 lb S02/MMBtu heat input in standalone operation or in combined cycle operation with Gas Turbine 1, averaged over 30 

boiler operating days. 

3. Steam Unit I shall not emit more than 0.0075 lb PM10/MMBtu heat input in standalone operation or in combined cycle operation with Gas Turbine 1, averaged over 30 

boiler operating days. 

4. Effective December 5, 2017, Steam Unit I shall not emit NOx in stand-alone 

operation in excess of 0.056 lb/MMBtu heat input, averaged over 30 boiler operating 

days. 

5. Effective December 5, 2017, Steam Unit 1 and Gas Turbine I in combined cycle 

operation shall not emit NOx in excess of 0.10 lb/MMBtu heat input, averaged over 

30 boiler operating days. 

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III. Best Available Retrofit Technology for Steam Units 2 and 3 

A. Compliance with Best Available Retrofit Technology Limits on NOx emiSSions from 

Steam Units 2 and 3 

1. Compliance during a boiler operating day when both units are operating IS 

demonstrated when either of the following conditions is met: 

a. The combined NOx emissions of Steam Units 2 and 3 meet the combined 

limit in Condition III.D; or 

b. Each unit meets its individual NOx limit in Conditions IILB and III. C. 

2. Compliance during a boiler operating day when only one unit is operating IS 

demonstrated when the operating tmit meets its individual NOx limit specified m 

Condition Ill.B or Ill. C. 

3. Except as provided in Conditions III.B.2 and III.C.2, the Permittee may comply with 

the limits in Section III through any combination of process adjustments or add-on 

controls (or use of pipeline quality natural gas in lieu of coal in Steam Unit 3), 

provided that such combination achieves the emission limit (on a 30-day rolling 

average basis), complies with applicable regulations and permits and the Permittee 

obtains any necessary preconstruction or operating approvals. 

B. Best Available Retrofit Technology Limits for Steam Unit2 

1. Effective December 5, 2016, Steam Unit 2 shall not emit S02 in excess of 0.15 

lb/MMBtu heat input, averaged over 30 boiler operating days and shall not emit PMw 

in excess of 0.03 lb/MMBtu heat input (filterable only), averaged over 30 boiler 

operating days. 

2. Effective December 5, 2017, Steam Unit 2 shall bum only pipeline quality natural gas 

except in the event of an emergency as defined in Section III.E. 

3. Effective December 5, 2017, Steam Unit 2 shall not emit NOx in excess of 0.085 

lb/MMBtu heat input, averaged over 30 boiler operating days, SOz in excess of 

0.00064 lb/MMBtu heat input, averaged over 30 boiler operating days, and PM10 in 

excess of 0.01 lb/MMBtu heat input (filterable + condensable), averaged over 30 

boiler operating days. 

4. Effective December 5, 2018, Steam Unit 2 shall not emit PMw in excess of 0.008 

lb/MMBtu heat input (filterable + condensable), averaged over 30 boiler operating 

days. 

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technology. The SNCR shall operate at all times that Steam Unit 3 is in operation and 

exhaust gas temperatures equal or exceed the manufacturer's recommended minimum 

temperature for operation ofthe SNCR technology. 

3. Effective December 5, 2017, Steam Unit 3 shall not emit NOx in excess of 0.23 

lb/MMBtu heat input, averaged over 30 boiler operating days. 

D. Best Available Retrofit Technology Limits for Combined Operation of Steam Units 2 and 

3 

Effective December 5, 2017, in lieu of the individual limits set forth for NOx in 

Conditions IILB.3 and III.C.3, the combined NOx emissions of Steam Units 2 and 3, 

averaged over 30 boiler-operating days, shall not exceed the limit established in the 

following equation: 

Limit= (Unit 2 MMBtuGas *0.085 lb/MMBtuGas)+(Unit 2 lb/MMBtucoaJ)+(Unit 

3 MMBtu * 0.23 lb/MMBtu) 

(Unit 2 MMBtu +Unit 3 MMBtu) 

E. Emergency Provision for Steam Unit 2 

1. The Permittee will not operate Steam Unit 2 on coal after December 5, 2017 except in 

the event of a supply disruption caused by natural gas supplier or transporter pipeline 

failure, freeze-up or pipeline compression failure that reduces gas volume or gas 

pressure below that necessary for Apache Generating Station gas generation. The 

Pennittee must discontinue coal firing as expeditiously as possible after restoration of 

natural gas service at levels supporting continuous firing of Steam Unit 2 and in no 

event more than 48 hours after restoration of such service. 

2. During any such period of coal operation and for such period thereafter as provided in 

Section IILE.3, the Permittee shall comply with the emission limits set forth in 

Condition Ill.B.1 for PM10 and S02 and shall minimize NOx emissions by use of 

good combustion practices and not to exceed 0.37 lb/MMBtu, averaged over 30 

boiler-operating days. 

3. Effective with the next boiler operating day after natural gas operation is restored for 

NOx and S02, and within 90 boiler operating days after natural gas operation is 

restored for PM10, the Permittee shall resume compliance with the applicable 

emissions limits set forth in Conditions III.B or IILD, as applicable. 

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its conversion to pipeline natural gas, but shall then comply with Condition IV.C.4. 

2. At all times, the Permittee shall maintain, calibrate, and operate a CEMS, in full 

compliance with the requirements fmmd at 40 CFR Part 75, to accmately measure 

NOx, diluent, and stack gas volumetric flow rate from Steam Unit I. 

3. Except as provided herein, all valid CEMS hourly data shall be used to detennine 

compliance with the emission limitations for NOx and S02 (when applicable) in 

Sections II and III for each unit. When the CEMS is out-of-control as defined by Part 

75, that CEMS data shall be treated as missing data and not used to calculate the 

emission average of the affected unit. Each required CEMS must obtain valid data for 

at least 90 percent of the unit operating hours, on an annual basis. 

4. The Permittee shall comply with the quality assurance procedures for CEMS found in 

40 CFR Part 75. In addition to these Part 75 requirements, relative accuracy test 

audits shall be calculated for both the NOx and S02 pounds per hour measurement 

and the heat input measurement. The CEMs monitoring data shall not be bias 

adjusted. 

5. Heat input for Steam Unit 1 and Gas Turbine 1 shall be measured in accordance with 

Part 75 fuel gas measurement procedures found in 40 CFR Part 75, Appendix D. 

B. Compliance Determinations for NOx. 

I. Effective December 5, 2017, the 30-day rolling average NOx emission rate for each 

of the following: stand-alone operation of Steam Unit I, combined cycle operation of 

Steam Unit 1 and Gas Turbine 1, Stean1 Unit 2, Steam Unit 3, and combined Steam 

Units 2 and 3, shall be calculated for each calendar day that the unit operates in 

accordance with the following procedure: 

a. Step One: For each unit\ sum the hourly pounds of NOx emitted during the 

current boiler-operating day and the preceding twenty-nine (29) boiler 

operating days, to calculate the total pounds of NOx emitted over the most 

recent thirty (30) boiler-operating day period for each coal-fired unit, except 

that for Steam Unit 1 and Gas Turbine I during the combined wmming/drying 

operation described in Condition ILA.2.b, all emissions are excluded; 

b. Step Two: For each unit, sum the hourly heat input, in MMBtu, during the 

current boiler operating day and the preceding twenty nine (29) boileroperating days, to calculate the total heat input, in MMBtu, over the most 

recent thirty (30) boiler-operating day period for each coal-fired unit. For 

Steam Unit 1 and Gas Turbine 1 operating in combined cycle operation, 

MMBtu from both units shall be included in this calculation; but for Steam 

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comply with the limits in Condition II.B.5, and whether Stearn Units 2 and 3 

comply with the limits in Conditions III.B or III.C; 

d. Step Four: If demonstrating compliance for Steam Units 2 and 3 with the 

combined limit in Section III.D, sum together the total pounds ofNOx emitied 

from Steam Units 2 and 3 over each unit's most recent thirty (30) boileroperating day period (the most recent 30 boiler operating day periods for 

different units may be different); 

e. Step Five: Sum together the total heat input from Steam. Units 2 and 3 over 

each unit's most recent thirty (30) boiler-operating day period; 

f. Step Six: Divide the total pounds of NOx emitted from step four for Steam 

Units 2 and 3 by the total heat input from step five for Steam Units 2 and 3, to 

calculate the combined 30-day rolling average NOx emission rate for Steam 

Units 2 and 3, in pounds ofNOx per MMBtu, for each calendar day. 

2. Effective December 5, 2017, for purposes of determining compliance with the limit in 

Condition II.B.6, the 30-day rolling average NOx pound/day emission rate for standalone operation of Steam Unit 1 or combined cycle operation of Stemn Unit 1 and 

Gas Turbine I shall be calculated for each calendar day in which either stand-alone or 

combined cycle operation occurs in accordance with the following procedure: 

a. Sum the hourly pounds of NOx emitted on that calendar day and the hourly 

pounds of NOx emitted during the preceding twenty-nine (29) calendar days 

operation occurred, if any, to calculate the total pounds ofNOx emitted over 

the most recent thirty (30) calendar day period, except that for Steam Unit 1 

and Gas Turbine 1 during the combined warming/drying operation described 

in Condition TI.A.2.b, all emissions are excluded; 

b. Divide the sum by 30 to calculate the rolling calendar day average 

pound/day emission rate for Stearn Unit I in stand-alone operation and Steam 

Unit 1 and Gas Turbine 1 in combined cycle operation for comparison with 

the limit in Condition II.B.6. 

3. For purposes of determining compliance with the limit in Condition II.B.4, only NOx 

emissions generated and the heat input of fuel bumed during periods when Steam 

Unit 1 is operating in stm1d-alone operation shall be counted in the calculations 

required by Conditions IV.B.l.a through c. 

4. For purposes of determining compliance with the limit in Condition JI.B.5, only NOx 

emissions generated and the heat input of fuel burned during periods when Steam 

Unit 1 and Gas Turbine 1 are operating in combined cycle operation shall be counted 

in the calculations required by Conditions IV.B.l.a through c. 

5. Except as otherwise provided in tills Condition IV.B, each 30-day rolling average 

NOx emission rate shall include all emissions and all heat input that occur during all 

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IV.B.l step three AND it meets the NOx lb/day limit in Condition 

ILB.6 as calculated in Condition IV .B.2; OR 

Ul. It is not operating during that calendar day. 

b. For Steam Units 2 and 3: 

1. Each operating unit meets its individual NOx limit in Condition ULB 

or III.C respectively as calculated in step three; OR 

u. The combined Steam Units 2 and 3 average meets its combined NOx 

limit in Condition III.D as calculated in step six; OR 

111. The unit is not operating during that calendar day. 

7. If a valid NOx pounds per hour or heat input is not available for any hour for a unit, 

that heat input and NOx pounds per hour shall not be used in the calculation of the 

30-day rolling average, except that if only NOx pounds per hour data arc available, it 

may be used to calculate compliance with the pound per day limit in Condition II.B.6, 

if applicable, in accordance with Condition IV .B.2. 

C. Compliance Determinations for S02 

1. Effective December 5, 2016, the 30-day rolling average S02 emission rate for Steam 

Units 2 and 3 shall be calculated for each calendar day on which the unit operates in 

accordance with the following procedure: 

a. Step One: Sum the total pounds of S02 emitted from the unit during the 

current boiler-operating day and the previous twenty-nine (29) boileroperating days; 

b. Step Two: Sum the total heat input to the unit in MMBtu during the current 

day and the previous twenty-nine (29) boiler-operating day; 

c. Step Three: Divide the total number of pounds of S02 emitted during the 

thirty (30) boiler-operating days by the total heat input during the thirty (30) 

boiler-operating days. A new 30-day rolling average S02 emission rate shall 

be calculated for each new boiler-operating day. 

2. Each 30-day rolling average S02 emission rate shaH include all emissions and all 

heat input that occur during all periods within any boiler-operating day, including 

emissions from startup, shutdown, and malfunction. 

3. If a valid S02 pounds per hour at the outlet of the FGD system or heat input is not 

available for any hour for a unit, that heat input and S02 pounds per hour shall not be 

used in the calculation of the 30-day rolling average. 

4. Compliance is demonstrated if each operating unit meets its individual S02 limit in 

Condition III.B or Ili.C respectively as calculated in step three OR if the unit is not 

operating during that calendar day. 

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efficiency of the SDAS unit and converted to SOz and units of the standard. 

D. Compliance Determinations for PM10 

I. Compliance with the particulate matter emission limitation for Steam Units 2 and 3 

shall be detennined from annual perfonnance stack tests. Within one hundred eighty 

(180) days of the compliance deadline specified in Conditions 111.8 or TII.C of this 

Attachment, and on at least an annual basis thereafter, the Permittee shall conduct a 

stack test on Stearn Unit 2 and 3 to measure PM10 using EPA Method 5, in 40 CFR 

part 60, Appendix A, or Method 201A/202 in 40 CFR Part 51, Appendix M. 

2. Steam Unit 2, after conversion to pipeline natural gas, shall demonstrate compliance 

with its limits in Conditions III.B.l, III.B.3 and III.B.4 within 90 days of the effective 

dates specified in Conditions III.B.l, III.B.3 and 111.8.4 respectively. Compliance for 

Steam Unit 2 shall be demonstrated using EPA Method 5, in 40 CFR part 60, 

Appendix A and Method 202, in 40 CFR Part 51, Appendix M, or EPA Method 

201A/202 in 40 CFR Part 51, Appendix M. 

3. Steam Unit 1 and Steam Unit 2, after completing the testing required in Conditions 

IV.D.l and IV.D.2, shall demonstrate compliance through use of pipeline quality 

natural gas. 

4. A test protocol shall be submitted to ADEQ a minimum of 30 days prior to the 

scheduled testing. The protocol shall identify which method(s) will be used to 

demonstrate compliance. Each test shall consist of three runs, with each run at least 

120 minutes in duration and each run collecting a minimum sample of 60 dry 

standard cubic feet. Results shall be reported inlb/MMBtu using the calculation in 40 

CFR Part 60 Appendix A Method 19. 

5. In addition to required stack tests, the owner/operator shall monitor particulate 

emissions for compliance with the emission limitations in accordance with any 

applicable Compliance Assurance Monitoring (CAM) plan developed and approved 

in accordance with 40 CFR Part 64. The averaging time for any other demonstration 

ofPM10 compliance or exceedance shall be based on a 6whour average. 

V. Recordkeeping, Reporting and Miscellaneous Provisions 

A. Recordkeeping. 

The Pem1ittee shall maintain the following records for at least five (5) years: 

1. All CEMS data, including the date, place, and time of sampling or 

measurement; parameters sampled or measured; and results. 

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6. Any other records required by 40 CFR Part 75. 

B. Reporting. 

1. The Permittee shall notify the Director and EPA Region 9 within two weeks after 

completion of installation of combustion controls or Selective Non-Catalytic Reactors 

on any of the tmits subject to this Attachment. 

2. Within 30 days after the applicable compliance date(s) in Conditions II.B, IILB, III.C 

and III.D, and within 30 days of every second calendar quarter thereafter (i.e., semiannually), the Peimittee shall submit a report that lists the daily 30-day rolling 

emission rates for NOx and S02 for each unit, calculated in accordance with Section 

IV of this Attachment. Included in this repori shall be the results of any relative 

accuracy test audit performed during the two preceding calendar quarters. 

C. Equipment Operations. 

At all times, including periods of stmtup, shutdown, and malfunction, the Pennittee shall, 

to the extent practicable, maintain and operate the unit including associated air pollution 

control equipment in a manner consistent with good air pollution control practices for 

minimizing emissions. Pollution control equipment shall be designed atld capable of 

operating properly to minimize emissions during all expected operating conditions. 

Determination of whether acceptable operating and maintenance procedures are being 

used will be based on information available to the Director, which may include, but is not 

limited to, monitoring results, review of operating and maintenance procedures, and 

inspection of the unit. 

D. Affinnative Defense for Malfunctions 

The following regulations are incorporated by reference and made part of this pennit and 

state implementation plan: 

1. R18-2-101, paragraph 65; 

2. R!S-2-310, sections (A), (B), (D) and (E) only; and 

3. R18-1-310.01. 

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boiler operating day does not include any day in which the only operation is the 

combined warming/drying operation with Gas Turbine 1 as defined in Condition II.B.2.b. 

For purposes of the limit in Condition II.B.4, "boiler operating days" shall include only 

those days during which Steam Unit 1 operates in stand-alone mode. For purposes of the 

limit in Condition II.B.5, "boiler operating days" shall include only those days during 

which Steam Unit 1 and Gas Turbine 1 operate in combined cycle mode. 

Flue Gas Desulfurization System or FGD means a pollution control device that employs 

flue gas desulfurization technology, including an absorber utilizing lime, fly ash, or 

limestone slurry, for the reduction of sulfur dioxide emissions. 

Operating hour means any hour that fossil fuel is fired in the unit, except that for Steam 

Unit I, operating hour does not include any hour in which the only operation is the 

combined warming/drying operation with Gas Turbine 1 as defined in Condition Il.B.2.b. 

Valid data means data recorded when the CEMS is not out-of-control as defined by Part 75. 

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