AQ0173TVP02 Final Permit SOB 012712 - Sierra Club · AIR QUALITY OPERATING PERMIT ... Million standard cubic feet MR&R.....Monitoring, Recordkeeping, ... or equal to a nominal ten

DEPARTMENT OF ENVIRONMENTAL CONSERVATIONAIR QUALITY OPERATING PERMIT

Permit No. AQ0I73TVPO2 Issue Date: February 3,2012Expiration Date: February 3, 2017

The Department of Environmental Conservation, under the authority of AS 46.14 and18 AAC 50, issues an operating permit to the Permittee, Golden Valley Electric Association,Inc., for the operation of the Healy Power Plant.

This permit satisfies the obligation of the owner and operator to obtain an operating permit as setout in AS 46.14.130(b).

As set out in AS 46.14.120(e), the Permittee shall comply with the terms and conditions of thisoperating permit.

Citations listed herein are contained within 18 AAC 50 dated September 17, 2011, Register 199.All Federal regulation citations are from those sections adopted by reference in this version ofregulation in 18 AAC 50.040 unless otherwise specified.

Upon effective date of this permit, Operating Permit No. AQO I 73TVPO 1, Revision 2 expires.This Operating Permit becomes effective March 3, 2012.

John F Kuterbach, lvi’ ager

Air Permits Program

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Permit No. AQ0173TVP02 Issued: February 3, 2012 Healy Power Plant Expires: February 3, 2017

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Table of Contents

Section 1. Stationary Source Information .....................................................................................1

Identification ................................................................................................................1 Names and Addresses .................................................................................................. 1

Section 2. Emission Unit Inventory and Description ....................................................................2

Section 3. State Requirements .......................................................................................................3

Visible Emissions Standards ........................................................................................3 Visible Emissions Monitoring, Recordkeeping and Reporting ....................................3 Particulate Matter Emissions Standards ...................................................................... 8 PM Monitoring, Recordkeeping and Reporting .......................................................... 8 Sulfur Compound Emission Standards Requirements .............................................. 11 BACT, Owner Requested Limits, and Other Title I Permit Requirements ............... 12 Insignificant Emission Units ......................................................................................24

Section 4. Conditions for Coal-Fired Boilers, Including Standard Operating Conditions for Boilers in Operation before July 1972. .................................................................25

Section 5. Performance Audits for COMS ..................................................................................31

Section 6. Federal Requirements .................................................................................................33

Emission Units Subject to Federal New Source Performance Standards (NSPS), Subpart A .....................................................................................................33 Steam Generating Units Subject to NSPS Subpart Dc ...............................................41 Non-Metallic Mineral Processing Subject to NSPS Subpart OOO ............................43 Emission Units/Stationary Sources Subject to Federal National Emission Standards for Hazardous Air Pollutants (NESHAPs) General Provisions .................44 Stationary Reciprocating Internal Combustion Engines Subject to 40 C.F.R. Part 63, Subpart ZZZZ (EU ID 5) ..............................................................................45 NESHAP for Area Sources: Industrial, Commercial, and Institutional Boilers, 40 C.F.R. 63, Subpart JJJJJJ (EU IDs 3 and 4) ..........................................................46

Section 7. General Conditions .....................................................................................................48

Standard Terms and Conditions .................................................................................48 NESHAPs Applicability Determinations ...................................................................51 Halon Prohibitions, 40 C.F.R. 82 ...............................................................................53 Open Burning Requirements ......................................................................................54

Section 8. General Source Testing and Monitoring Requirements .............................................55

Section 9. General Recordkeeping and Reporting Requirements ...............................................58

Recordkeeping Requirements .....................................................................................58 Reporting Requirements .............................................................................................58

Section 10. Permit Changes and Renewal .....................................................................................62


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Section 11. Compliance Requirements ..........................................................................................65

General Compliance Requirements ............................................................................65

Section 12. Permit As Shield from Inapplicable Requirements ....................................................67

Section 13. Visible Emissions Forms ............................................................................................69

Visible Emissions Field Data Sheet ...........................................................................69 Visible Emissions Observation Record ......................................................................70

Section 14. Material Balance Calculation .....................................................................................71

Section 15. ADEC Notification Form ...........................................................................................72


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List of Abbreviations Used in this Permit

AAC ............Alaska Administrative Code

ADEC ..........Alaska Department of Environmental Conservation

AS ...............Alaska Statutes ASTM .........American Society for

Testing and Materials BACT ..........Best Available Control

Technology BHp .............Boiler Horsepower C.F.R. ..........Code of Federal

Regulations The Act........Clean Air Act CO ...............Carbon Monoxide dscf ..............Dry standard cubic foot EPA .............US Environmental

Protection Agency EU ...............Emission Unit gr./dscf ........grain per dry standard cubic

foot (1 pound = 7000 grains)

GPH.............gallons per hour HAPs ...........Hazardous Air Pollutants

[HAPs as defined in AS 46.14.990]

ID ................Emission Unit Identification Number

kPa...............kiloPascals LAER ..........Lowest Achievable

Emission Rate MACT .........Maximum Achievable

Control Technology as defined in 40 C.F.R. 63.

MMBtu/hr ...Million British thermal units per hour

MMSCF ......Million standard cubic feet MR&R.........Monitoring,

Recordkeeping, and Reporting

NESHAPs ......Federal National Emission Standards for Hazardous Air Pollutants [NESHAPs as contained in 40 C.F.R. 61 and 63]

NOX ................Nitrogen Oxides NSPS ..............Federal New Source

Performance Standards [NSPS as contained in 40 C.F.R. 60]

O & M ............Operation and Maintenance O2 ...................Oxygen PAL ................Plantwide Applicability

Limitation PM-10 ............Particulate Matter less than

or equal to a nominal ten microns in diameter

ppm ...............Parts per million

ppmv, ppmvd Parts per million by volume on a dry basis

psia .................Pounds per Square Inch (absolute)

PSD ................Prevention of Significant Deterioration

PTE ................Potential to Emit SIC. ................Standard Industrial

Classification SO2 .................Sulfur dioxide TPH ................Tons per hour TPY ................Tons per year VOC ...............volatile organic compound

[VOC as defined in 40 C.F.R. 51.100(s)]

VOL ...............volatile organic liquid [VOL as defined in 40 C.F.R. 60.111b, Subpart Kb]

vol% ...............volume percent wt% ................weight percent


Page 1 of 74

Section 1. Stationary Source Information

Identification

Names and Addresses

Permittee: Golden Valley Electric Association, Inc. P.O. Box 71249 Fairbanks, Alaska 99707-1249

Stationary Source Name: Healy Power Plant Location: 63˚ 51 00 North; 148˚ 58 00 West Physical Address: Mile 2.5 Healy Spur Road, Healy, Alaska 99743

Owner(s): GVEA (owner of Unit No. 1 system) P.O. Box 71249 Fairbanks, Alaska 99707-1249

Alaska Industrial Development and Export Authority AIDEA (owner of Unit 2 HCCP system) 813 West Northern Lights Boulevard Anchorage, Alaska 99503

Operator: Golden Valley Electric Association P.O. Box 71249 Fairbanks, Alaska 99707-1249

Permittee’s Responsible Official Ms. Kathryn Lamal Vice President of Power Supply

Designated Agent: Ms. Kristen DuBois Environmental Officer P.O. Box 71249 Fairbanks, Alaska 99707-1249

Stationary Source and Building Contact:

Mr. David Hoffman Plant Manager (907) 683-8324

Fee Contact: Ms. Kristen DuBois Environmental Officer P.O. Box 71249 Fairbanks, Alaska 99707-1249

Permit Contact: Ms. Kristen DuBois Environmental Officer P.O. Box 71249 Fairbanks, Alaska 99707-1249

Process Description: SIC Code: 4911 – Electrical Services Establishments engaged in the generation, transmission, and/or distribution of electric energy for sale


Page 2 of 74

Section 2. Emission Unit Inventory and Description Emission units listed in Table A have specific monitoring, record keeping, or reporting conditions in this permit. Emission unit descriptions and ratings are given for identification purposes only.

Table A - Emission Units Inventory

EU ID Emission Unit Name Emission Unit Description Rating/Size

Construction Date

1 Unit #1 Foster-Wheeler Boiler pulverized coal fired steam generator with a 12 module ICA baghouse

327 MMBtu/hr 1967

2 HCCP

TRW Integrated Entrained Combustion System pulverized coal-fired steam generator, Joy Activated Recycle Spray Dryer Absorber, and Joy Pulse Jet Fabric Filter

658 MMBtu/hr 1996

3 Auxiliary Heater #1 Cleaver Brooks CB 300-15 Standby process and building heater

10.4 MMBtu/hr 1967

4 Auxiliary Heater #2 Cleaver Brooks CB 800 Standby process and building heater

23.0 MMBtu/hr 1996

5 Diesel Generator #1 Electro-Motive Diesel EMD 20-645-E4 Standby diesel electric generator set

2.75 MW 1967

6 Crusher System (dust collector #1)

Crusher System: 2 grizzlies, 1 primary Stamler crusher, 2 belt feeders, 2 secondary crushers, 2 hoppers, and the #1 conveyor belt (tail-end), all commonly vented to dust collector #1 (baghouse/exhaust fan).

400 tons/hr 1996

7 Lime Storage Silo Limestone Storage Silo with baghouse 314 tons 1996

8 Flyash Storage Silo Flyash Storage Silo with baghouse 570 tons 1996

9 Trona Handling System

Trona Handling System: Mill, trona silo, and baghouse

50 ton 1998

10 Coal Handling System (dust collector #2)

Coal Handling System: #1 conveyor belt (head-end), #2a conveyor belt, #2b conveyor belt, one bucket elevator, #3 conveyor belt, #4 conveyor belt, two 600 ton HCCP coal storage silos, two Unit #1 bunkers, all commonly vented to dust collector #2 (baghouse/exhaust fan). Note: When HCCP is not operational, dust is collected at the Emission Unit #1 transfer points via a temporary dust collector (baghouse/exhaust fan).

240 tons of coal/hr 1996

13 Firewater Pump Engine

Caterpillar Diesel Model 3406B

264 hp 1997

Fugitive Emission Sources

11 Haul Road (located on GVEA property) ¼ mi. from Usibelli Coal Mine property line to coal pile

12 Coal Storage Pile

Up to a 30 day coal supply w/ both EU IDs 1 and 2 operating

[18 AAC 50.326(a)] [40 C.F.R. 71.5(c)(3)]


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Section 3. State Requirements

Visible Emissions Standards

1. Industrial Process and Fuel-Burning Equipment Visible Emissions. The Permittee shall comply with the following:

1.1 Do not cause or allow visible emissions, excluding condensed water vapor, emitted from EU IDs 3 through 6, 9 and 10 listed in Table A to reduce visibility through the exhaust effluent by more than 20 percent averaged over any six consecutive minutes.

[18 AAC 50.040(j), 50.055(a)(1) & 50.055(a)(5); and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(1)]

1.2 For EU IDs 6, 9 and 10 monitor, record and report in accordance with Conditions 2 through 4.

[18 AAC 50.040(j), 7/25/08; 18 AAC 50.326(j) and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)]

1.3 For EU IDs 3 through 5, as long as each emission unit does not exceed 400 hours of total (emergency and non-emergency hours combined) operation per calendar year, monitoring shall consist of an annual certification of compliance with the opacity standard. Otherwise, monitor, record, and report visible emissions in accordance with Conditions 2 - 4. The Permittee shall report under Condition 100 if any of EU IDs 3 through 5 exceeds 400 operating hours, and becomes subject to Conditions 2 - 4, and if such unit exceeds 800 hours, and becomes subject to Condition 2.1g.

[18 AAC 50.040(j), 7/25/08; 18 AAC 50.326(j) and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)]

Visible Emissions Monitoring, Recordkeeping and Reporting

EU IDs 3 through 6, 9 and 10

2. Visible Emissions Monitoring. The Permittee shall observe the exhaust of EU IDs 3 through 6, 9 and 10 for visible emissions using either the Method 9 Plan under Condition 2.1or the Smoke/No-Smoke Plan1 under Condition 2.2. The Permittee may change visible-emissions plans for an emission unit at any time unless prohibited from doing so by Condition 2.3. The Permittee may elect to continue a visible emission monitoring schedule in effect from the previous permit at the time a renewed permit is issued if applicable.

[18 AAC 50.040(j); 18 AAC 50.326(j) and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(i)]

2.1 Method 9 Plan. For all 18-minute observations in this plan, observe exhaust, following 40 C.F.R. 60, Appendix A-4, Method 9, adopted by reference in 18 AAC 50.040(a), for 18 minutes to obtain 72 consecutive 15-second opacity observations.

1 In this permit, for monitoring visible emissions, the term “smoke” also means visible emissions that are not products of combustion.


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EU IDs 6 through 10 (Coal Handling and Associated Systems)

a. First Method 9 Observation. Unless electing to continue a visible emission monitoring schedule in effect from the previous permit, observe exhaust for 18 minutes within six months after the issue date of this permit. For any emission unit, observe exhaust for 18 minutes within 14 calendar days after changing from the Smoke/No-Smoke Plan of Condition 2.2. For any emission units replaced during the term of this permit, observe exhaust for 18 minutes within 30 days of startup.

b. Monthly Method 9 Observations. After the first Method 9 observation, perform 18-minute observations at least once in each calendar month that an emission unit operates.

c. Semiannual Method 9 Observations. After observing emissions for three consecutive operating months under Condition 2.1b, unless a six-minute average is greater than 15 percent and one or more observations are greater than 20 percent, perform 18-minute observations at least semiannually.

Semiannual observations must be taken between four and seven months after the previous set of observations.

d. Annual Method 9 Observations. After at least two semiannual 18-minute observations, unless a six-minute average is greater than 15 percent and one or more individual observations are greater than 20 percent, perform 18-minute observations at least annually.

Annual observations must be taken between 10 and 13 months after the previous observations.

e. Increased Method 9 Frequency. If a six-minute average opacity is observed during the most recent set of observations to be greater than 15 percent and one or more observations are greater than 20 percent, then increase or maintain the 18-minute observation frequency for that emission unit to at least monthly intervals, until the criteria in Condition 2.1c for semiannual monitoring are met.

EU IDs 3 through 5 (Fuel Burning Equipment)

f. First Method 9 Observation. Observe exhaust while firing on liquid fuel per Condition 2.1 within 30 days after the end of a calendar month in which the cumulative hours of operation on liquid fuel for the past calendar year exceed 400 hours, except

(i) when an 18-minute Method 9 observation has already been conducted in accordance with Condition 2.1 in the same calendar year period, and

(ii) the emission unit appears to not have excess visible emissions while in operation on liquid fuel.


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g. Second Method 9 Observation. Observe exhaust per Condition 2.1 within 30 days after the end of a calendar month in which the cumulative hours of operation for the past calendar year exceed 800 hours.

h. Increased Method 9 Frequency. If a six-minute average opacity is observed during the most recent set of observations to be greater than 15 percent and one or more observations are greater than 20 percent, then increase or maintain the 18-minute observation frequency for that emission unit to at least monthly intervals, until a six-minute average opacity observed during the most recent set of observations is not greater than 15 percent or no observation is greater than 20 percent.

Observations are not required under this Condition 2.1h if the emission unit is not otherwise operated during the month.

2.2 Smoke/No Smoke Plan. Observe the exhaust for the presence or absence of visible emissions, excluding condensed water vapor.

a. Initial Monitoring Frequency. Observe the exhaust during each calendar day that an emission unit operates.

b. Reduced Monitoring Frequency. After the emission unit has been observed on 30 consecutive operating days, if the emission unit operated without visible smoke in the exhaust for those 30 days, then observe emissions at least once in every calendar month that an emission unit operates.

c. Smoke Observed. If smoke is observed, either begin the Method 9 Plan of Condition 2.1 or perform the corrective action required under Condition 2.3.

2.3 Corrective Actions Based on Smoke/No Smoke Observations. If visible emissions are present in the exhaust during an observation performed under the Smoke/No Smoke Plan of Condition 2.2, then the Permittee shall either follow the Method 9 plan of Condition 2.1 or

a. initiate actions to eliminate smoke from the emission unit within 24 hours of the observation;

b. keep a written record of the starting date, the completion date, and a description of the actions taken to reduce smoke; and

c. after completing the actions required under Condition 2.3a,

(i) take Smoke/No Smoke observations in accordance with Condition 2.2.

(A) at least once per day for the next seven operating days and until the initial 30 day observation period is completed; and

(B) continue as described in Condition 2.2b; or


Page 6 of 74

(ii) if the actions taken under Condition 2.3a do not eliminate the smoke, or if subsequent smoke is observed under the schedule of Condition 2.3c(i)(A), then observe the exhaust using the Method 9 Plan unless the Department gives written approval to resume observations under the Smoke/No Smoke Plan; after observing smoke and making observations under the Method 9 Plan, the Permittee may at any time take corrective action that eliminates smoke and restart the Smoke/No Smoke Plan under Condition 2.2a.

3. Visible Emissions Recordkeeping. The Permittee shall keep records as follows: [18 AAC 50.040(j); 18 AAC 50.326(j), and 18 AAC 50.346(c)]

[40 C.F.R. 71.6(a)(3)(ii)]

3.1 When using the Method 9 Plan of Condition 2.1,

a. the observer shall record

(i) the name of the stationary source, emission unit and location, emission unit type, observer's name and affiliation, and the date on the Visible Emissions Field Data Sheet in Section 13;

(ii) the time, estimated distance to the emissions location, sun location, approximate wind direction, estimated wind speed, description of the sky condition (presence and color of clouds), plume background, and operating rate (load or fuel consumption rate) on the sheet at the time opacity observations are initiated and completed;

(iii) the presence or absence of an attached or detached plume and the approximate distance from the emissions outlet to the point in the plume at which the observations are made;

(iv) opacity observations to the nearest five percent at 15-second intervals on the Visible Emissions Observation record in Section 13, and

(v) the minimum number of observations required by the permit; each momentary observation recorded shall be deemed to represent the average opacity of emissions for a 15-second period.

b. for EU IDs 3 through 6, 9 and 10, to determine the six-minute average opacity, divide the observations recorded on the record sheet into sets of 24 consecutive observations; sets need not be consecutive in time and in no case shall two sets overlap; for each set of 24 observations, calculate the average by summing the opacity of the 24 observations and dividing this sum by 24; record the average opacity on the sheet.

c. for EU IDs 3 through 6, 9 and 10 calculate and record the highest 18-consecutive-minute averages observed.

3.2 If using the Smoke/No Smoke Plan of Condition 2.2, record the following information in a written log for each observation and submit copies of the recorded information upon request of the Department:


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a. the date and time of the observation;

b. from Table A, the ID of the emission unit observed;

c. whether visible emissions are present or absent in the exhaust;

d. a description of the background to the exhaust during the observation;

e. if the emission unit starts operation on the day of the observation, the startup time of the emission unit;

f. name and title of the person making the observation; and

g. operating rate (load or fuel consumption rate).

4. Visible Emissions Reporting. The Permittee shall report visible emissions as follows: [18 AAC 50.040(j); 18 AAC 50.326(j), and 18 AAC 50.346(c)]

[40 C.F.R. 71.6(a)(3)(iii)]

4.1 in each stationary source operating report under Condition 100, include for the period covered by the report:

a. which visible-emissions plan of Condition 2 was used for each emission unit; if more than one plan was used, give the time periods covered by each plan;

b. for each emission unit under the Method 9 Plan,

(i) copies of the observation results (i.e. opacity observations) for each emission unit that used the Method 9 Plan, except for the observations the Permittee has already supplied to the Department; and

(ii) a summary to include:

(A) number of days observations were made;

(B) highest six-minute average observed; and

(C) dates when one or more observed six-minute averages were greater than 20 percent;

c. for each emission unit under the Smoke/No Smoke Plan, the number of days that Smoke/No Smoke observations were made and which days, if any, that smoke was observed; and

d. a summary of any monitoring or record keeping required under Conditions 2 and 3 that was not done;

4.2 Report under Condition 99:

a. the results of Method 9 observations that exceed an average of 20 percent opacity for any six-minute period; and

b. if any monitoring under Condition 2 was not performed when required, report within three days of the date the monitoring was required.


Page 8 of 74

Particulate Matter Emissions Standards

5. Industrial Process and Fuel-Burning Equipment Particulate Matter. The Permittee shall not cause or allow particulate matter emitted from EU ID(s) 3 through 5 listed in Table A to exceed 0.05 grains per cubic foot of exhaust gas corrected to standard conditions and averaged hourly, EU ID 9 listed in Table A to exceed 0.05 grains per cubic foot of exhaust gas corrected to standard conditions and averaged over three hours, and EU ID(s) 6 and 10 listed in Table A to exceed 0.02 grains per cubic foot of exhaust gas corrected to standard conditions and averaged hourly.

[18 AAC 50.040(j), 50.055(b)(1), & 50.346(c); and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(1)]

[AQC Permit #9431-AA001, Conditions 45, 46, 47, and Exhibit B]

5.1 For EU IDs 3 through 5, as long as each emission unit does not exceed 400 hours of total (emergency and non-emergency hours combined) operation per calendar year, monitoring shall consist of an annual certification of compliance with the particulate matter standard. Otherwise, for emission units 3 and 4, monitor, record and report in accordance with Conditions 8, 9 and 10, and for emission unit 5, monitor, record and report in accordance with Conditions 6, 7 and 10.

[18 AAC 50.040(j), 7/25/08; 18 AAC 50.326(j), 12/1/04 and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)]

PM Monitoring, Recordkeeping and Reporting

Diesel Engines (EU ID 5)

6. Particulate Matter Monitoring for Diesel Engines. The Permittee shall conduct source tests on the diesel engine, EU ID 5, to determine the concentration of particulate matter (PM) in the exhaust of the emission unit in accordance with this Condition 6.

[18 AAC 50.040(j); 18 AAC 50.326(j), and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(i)]

6.1 Except as provided in Condition 6.4 within six months of exceeding the criteria of Conditions 6.2a or 6.2b, either

a. conduct a PM source test according to requirements set out in Section 8; or

b. make repairs so that emissions no longer exceed the criteria of Condition 6.2; to show that emissions are below those criteria, observe emissions as described in Condition 2.1 under load conditions comparable to those when the criteria were exceeded.

6.2 Conduct the test according to Condition 6.1 if

a. 18 consecutive minutes of Method 9 observations result in an 18-minute average opacity greater than 20 percent; or

b. for an emission unit with an exhaust stack diameter that is less than 18 inches, 18 consecutive minutes of Method 9 observations result in an 18-minute average opacity that is greater than 15 percent and not more than 20 percent, unless the Department has waived this requirement in writing.


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6.3 During each one-hour PM source test run, observe the exhaust for 60 minutes in accordance with Method 9 and calculate the average opacity that was measured during each one-hour test run. Submit a copy of these observations with the source test report.

6.4 The automatic PM source test requirement in Conditions 6.1 and 6.2 is waived for an emission unit if a PM source test on that unit has shown compliance with the PM standard during this permit term.

7. Particulate Matter Reporting for Diesel Engines. The Permittee shall report as follows:

[18 AAC 50.040(j); 18 AAC 50.326(j), and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(iii)]

7.1 report under Condition 99

a. the results of any PM source test that exceeds the PM emissions limit; or

b. if one of the criteria of Condition 6.2 was exceeded and the Permittee did not comply with either Condition 6.1a or 6.1b, this must be reported by the day following the day compliance with Condition 6.1 was required;

7.2 report observations in excess of the threshold of Condition 6.2b within 30 days of the end of the month in which the observations occur;

7.3 in each operating report under Condition 100, include for the period covered by the report:

a. the dates, EU ID, and results when an observed 18-minute average was greater than an applicable threshold in Condition 6.2;

b. a summary of the results of any PM testing under Condition 6; and

c. copies of any visible emissions observation results (opacity observations) greater than the thresholds of Condition 6.2, if they were not already submitted.

Liquid-Fired Heaters and Boilers (EU IDs 3 and 4)

8. Particulate Matter Monitoring. The Permittee shall conduct source tests on EU IDs 3 and 4 to determine the concentration of PM in the exhaust of EU IDs 3 and 4 as follows:

[18 AAC 50.040(j), 18 AAC 50.326(j)(4), and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(i) & (c)(6)]

8.1 Conduct a PM source test according to the requirements set out in Section 8 no later than 90 calendar days after any time corrective maintenance fails to eliminate visible emissions greater than the 20 percent opacity threshold for two or more 18-minute observations in a consecutive six-month period.

8.2 During each one-hour PM source test run, observe the exhaust for 60 minutes in accordance with Method 9 and calculate the average opacity that was measured during each one-hour test run.


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8.3 The PM source test requirement in Condition 8 is waived for an emission unit if:

a. a PM source test during the most recent semiannual reporting period on that unit shows compliance with the PM standard since permit issuance, or

b. if a follow-up visible emission observation conducted using Method-9 during the 90 days shows that the excess visible emissions described in Condition 2.1e no longer occur.

9. Particulate Matter Recordkeeping. The Permittee shall keep records of the results of any PM testing and visible emissions observations conducted under Condition 8.

[18 AAC 50.040(j), 18 AAC 50.326(j)(4), and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(ii) & (c)(6),]

10. Particulate Matter Reporting. The Permittee shall report as follows: [18 AAC 50.040(j), , 18 AAC 50.326(j)(4), and 18 AAC 50.346(c),]

[40 C.F.R. 71.6(a)(3)(iii) & (c)(6),]

10.1 In each operating report required by Condition 100, include

a. the dates, EU ID(s), and results when an 18-minute opacity observation was greater than the applicable threshold criterion in Condition 2.1e.

b. a summary of the results of any PM testing and visible emissions observations conducted under Condition 8.

10.2 Report as excess emissions, in accordance with Condition 99, any time the results of a source test for PM exceeds the PM emission limit stated in Condition 5.

For Baghouses (EU IDs 6 through 10)

11. Particulate Matter Monitoring. The Permittee shall monitor particulate matter emissions from EU ID(s) 6 through 10 to determine the concentration of particulate matter (PM) in the exhaust in accordance with the following.

[18 AAC 50.040(j), and 18 AAC 50.326(j)(4),] [40 C.F.R. 71.6(a)(3)(i) & (c)(6),]

11.1 If the criteria of Condition 11.2a or 11.2b is exceeded,

a. perform an inspection of the bags and baghouse assembly to ascertain the integrity of the system;

(i) take steps to clean the bags of excess trapped dust;

(ii) if any bags are found with holes or tears or deterioration which renders them ineffectual, the bags shall be replaced within 24 hours;

(iii) if after cleaning the bags of excess dust or replacing torn or deteriorated bags, 18 consecutive minutes of Method 9 observations result in an 18-minute average opacity greater than 20 percent, conduct a PM source test within six months according to the requirements set out in Section 8 to confirm whether or not the PM emission limits in Conditions 5, 15 and 60 are being maintained;


Page 11 of 74

b. maintain the results of baghouse inspections, records of bags replaced, and repairs conducted at the source for inspection at the request of the Department.

11.2 Monitor according to Condition 11.1 if

a. 18 consecutive minutes of Method 9 observations result in an 18-minute average opacity greater than 20 percent, or

b. for an emission unit with an exhaust stack diameter that is less than 18 inches, 18 consecutive minutes of Method 9 observations result in an 18-minute average opacity that is greater than 15 percent and not more than 20 percent, unless the Department has waived this requirement in writing.

12. Particulate Matter Recordkeeping. The Permittee shall keep records of the results of any PM testing conducted under Condition 11.1a(iii).

[18 AAC 50.040(j), and 18 AAC 50.326(j)(4)] [40 C.F.R. 71.6(a)(3)(ii) & (c)(6)]

13. Particulate Matter Reporting. The Permittee shall report as follows: [18 AAC 50.040(j) and 18 AAC 50.326(j)(4)]

[40 C.F.R. 71.6(a)(3)(iii) & (c)(6)]

13.1 In each facility operating report required by Condition 100, include

a. a summary of the results of any PM testing conducted under Condition 11.1a(iii).

13.2 Report as excess emissions, in accordance with Condition 99, any time the results of a source test for PM exceeds the PM emission limit stated in Conditions 5, 15 and 60.

Sulfur Compound Emission Standards Requirements

14. Sulfur Compound Emissions. The Permittee shall not cause or allow sulfur compound emissions, expressed as SO2, from EU IDs 3 though 5 to exceed 500 ppm averaged over three hours.

[18 AAC 50.040(j) & 18 AAC 50.055(c), and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(1)]

For Fuel Oil2 (EU IDs 3 though 5)

14.1 The Permittee shall do one of the following for each shipment of fuel:

a. If the fuel grade requires a sulfur content less than 0.5 percent by weight, keep receipts that specify fuel grade and amount; or

b. If the fuel grade does not require a sulfur content less than 0.5 percent by weight, keep receipts that specify fuel grade and amount; and

2 Oil means crude oil or petroleum or a liquid fuel derived from crude oil or petroleum, including distillate and residual oil, as defined in 40 C.F.R. 60.41b, effective 10/08/09.


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(i) test the fuel for sulfur content; or

(ii) obtain test results showing the sulfur content of the fuel from the supplier or refinery; the test results must include a statement signed by the supplier or refinery of what fuel they represent.

14.2 Fuel testing under Condition 14.1 must follow an appropriate method listed in 18 AAC 50.035 or another method approved in writing by the Department.

14.3 If a load of fuel contains greater than 0.75 percent sulfur by weight, the Permittee shall calculate SO2 emissions in ppm using either Section 14 or Method 19 of 40 C.F.R. 60, Appendix A-7, adopted by reference in 18 AAC 50.040(a).

14.4 The Permittee shall report as follows:

a. If SO2 emissions calculated under Condition 14.3 exceed 500 ppm, the Permittee shall report under Condition 99. When reporting under this condition, include the calculation under Section 14.

b. The Permittee shall include in the report required by Condition 100

(i) a list of the fuel grades received at the stationary source during the reporting period;

(ii) for any grade with a maximum fuel sulfur greater than 0.5 percent sulfur, the fuel sulfur of each shipment; and

(iii) for fuel with a sulfur content greater than 0.75 percent, the calculated SO2 emissions in ppm.

[18 AAC 50.040(j); 18 AAC 50.326(j), and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)]

BACT, Owner Requested Limits, and Other Title I Permit Requirements

15. The Permittee shall limit short term emissions and calendar year emissions from EU IDs 1 through 8 and 10, as indicated in Table B.

[18 AAC 50.040(j) and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)]

[AQC Permit #9431-AA001, Exhibit B]

15.1 As applicable, the Permittee shall calculate and record the hourly average, 3-hour average, 30-day rolling average, annual average, and the monthly and calendar year summation of emissions of NOX and SO2 for EU IDs 1 through 5, PM for EU IDs 1 through 8 and 10, CO for EU IDs 2 and 4, and beryllium for EU ID 2.

a. Use continuous emission monitors to determine emissions of NOX from EU IDs 1 and 2 and AP-42 NOX emission factors for EU IDs 3 through 5.

b. Use continuous emissions monitors to determine emissions of SO2 from EU IDs 1 and 2 and the sulfur content of the fuel and the amount of fuel used to calculate emissions of SO2 from EU IDs 3 through 5.


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c. Use source test results to determine emissions of PM from EU IDs 1 and 2 and AP-42 PM emission factors for EU IDs 3 through 8 and 10.

d. Use AP-42 emission factors, along with the hours of operation and/or amount of fuel used, to calculate the emissions of CO for EU ID 4, and continuous emission monitors to determine emissions from EU ID 2.

e. Use the results from the quarterly beryllium analysis to ensure the beryllium concentration limit is not exceeded for EU ID 2.

15.2 As applicable, the Permittee shall report the hourly average, 3-hour average, 30-day rolling average, annual average, and the monthly and calendar year summation of emissions from EU IDs 1 through 8 and 10, as indicated in Table B, for each month of the reporting period with each facility operating report required by Condition 100.

15.3 Notify the Department per Condition 99 should the short term emissions and/or calendar year emissions from EU IDs 1 through 8 and 10 exceed the limit for that contaminant as indicated in Table B.


Page 14 of 74

Table B - BACT and Owner Requested Emission Limits

Pollutant

Emission Unit ID

Emission Unit

Description

Short Term Emission Limits Calendar Year

Emission Limits (tpy)

PM

1 Unit #1 0.05 gr/dscf, hourly average (36.7 lb/hr at full load)

161

2 HCCP 0.020 lb/MMBtu, hourly average (13.2 lb/hr at full load)

58

3 Aux #1 Heater 0.05 gr/dscf, hourly average (0.8 lb/hr at full load) 20% load factor, annual average

1

4 Aux #2 Heater 0.05 gr/dscf, hourly average (1.5 lb/hr at full load) 45% load factor, annual average

3

5 Diesel Generator #1 0.05 gr/dscf, hourly average (2.1 lb/hr at full load) 20% load factor, annual average

2.88

6 Primary Crusher 0.02 gr/dscf, hourly average (2.05 lb/ hr at 12,000 cfm)

3.00

7 Limestone Storage Silo 0.02 gr/dscf, hourly average (0.14 lb/hr at 800 cfm)

0.05

8 Spent Limestone/ Flyash Storage Silo

0.02 gr/dscf, hourly average (0.86 lb/hr at 5000 cfm)

3.8

10 Coal Handling System 0.02 gr/dscf, hourly average (3.43 lb/hr at 20,000 cfm)

5.01

Fugitive Sources 1

Total PM for all emission units 238.74


Page 15 of 74

Pollutant

Emission Unit ID

Emission Unit

Description

Short Term Emission Limits Calendar Year

Emission Limits (tpy)

NOX

1 Unit #1 429

2 HCCP 0.325 lb/MMBtu, 30-day rolling average 937

3 Auxiliary #1 Heater 20 lb NOx/1000 gal distillate fuel, annual average 20% load factor, annual average

2

4 Auxiliary #2 Heater 20 lb NOx/1000 gal distillate fuel, annual average 45% load factor, annual average

7

5 Diesel Generator #1

Not to exceed 370 lb NOx/1000 gal, annual average; 20% load factor, annual average

78

Total NOX for all emission units 1453

SO2

1 Unit #1 258 lb/hr, 24-hour average, calendar day 367 lb/hr, 3-hour average

472

2 HCCP 0.086 lb/MMBtu, annual average 0.10 lb/MMBtu (65.8 lb/hr), 3-hour average

248

3 Aux #1 Heater 0.3% S in oil, annual average 0.5% S in oil, 3-hour average

4

4 Aux #2 Heater 0.3% S in oil, annual average 0.5% S in oil, 3-hour average

15

5 Diesel Generator #1 0.3% S in oil, annual average 0.5% S in oil, 3-hour average

10

Total SO2 for all emission units 749

CO

2 HCCP 0.20 lb/MMBtu, hourly average (132 lb/hr) 577

4 Aux #2 Heater 5 lb/1000 gal, hourly average (0.8 lb/hr) 2

Total CO for EU IDs 2 and 4 579

Beryllium 2 HCCP Not to exceed 114 ppm in fuel, annual average

0.0005

[AQC Permit #9431-AA001, Conditions 45, 46, 47, and Exhibit B]


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16. Permittee shall operate EU ID 3 at no more than 20% of annual load capacity and combust only distillate fuel.


[AQC Permit #9431-AA001, Condition 6]

16.1 For EU ID 3, monitor and record the monthly hours of operation, operational load, and type of fuel combusted.

16.2 Report in the operating report of Condition 100 the monthly hours of operation totals, the monthly operational load totals, the calendar year-to-date totals, and the type of fuel combusted.

16.3 Report in accordance with Condition 99 whenever the load (%) multiplied by the operating hours exceeds 20% of the annual load capacity (i.e., greater than 0.20 X 8760 hrs X 10.4 MMBtu/hr) per calendar year or if other than distillate fuel is combusted.

16.4 Permittee may monitor, record, and report gallons of fuel combusted instead of operation load if only distillate fuel with a heating value of approximately 134,716 Btu/gallon is combusted in EU ID 3. Report in accordance with Condition 99 whenever the gallons combusted in EU ID 3 exceed 135,253 gallons per calendar year.

17. Permittee shall operate EU ID 4 at no more than 45% of annual load capacity and combust only distillate fuel.



17.1 For EU ID 4, monitor and record the monthly hours of operation, operational load, and type of fuel combusted.

17.2 Report in the operating report required by Condition 100 the monthly hours of operation totals, the monthly operational load totals, the calendar year-to-date totals, and the type of fuel combusted.

17.3 Report in accordance with Condition 99 whenever the load (%) multiplied by the operating hours exceeds 45% of the annual load capacity (i.e., greater than 0.45 X 8760 hrs X 23.0 MMBtu/hr) per calendar year or if other than distillate fuel is combusted.



Page 17 of 74

18. Permittee shall operate EU ID 5 at no more than 20% of annual load capacity.



18.1 For EU ID 5, monitor and record the monthly hours of operation and operational load.

18.2 Report in the operating report required by Condition 100 the monthly hours of operation totals, the monthly operational load totals, and the calendar year-to-date totals.

18.3 Report in accordance with Condition 99 whenever the load (%) multiplied by the operating hours exceeds 20% of the annual load capacity (i.e., greater than 0.20 X 8760 hrs X 32.33 MMBtu/hr) per calendar year.


19. Permittee shall operate a certified continuous opacity monitor on EU ID 1 consistent with Performance Specification 1 as described in 40 C.F.R. Part 60, Appendix B. If a new opacity monitor is to be installed, the selection, siting, and installation shall be approved by the Department.


[Construction permit #9831-AC018, Condition 21.3, AQC Permit #9431-AA001, Condition 10]

19.1 Monitor, record, and report in accordance with Section 4.

20. Permittee shall install and operate a continuous emission monitoring system on the EU ID 1 boiler exhaust duct to measure and record the calendar year emissions of SO2 and oxides of nitrogen discharged to the atmosphere.


[Construction permit #9831-AC018, Condition 25.1, and AQC Permit #9431-AA001, Conditions 51 and 52]

20.1 Monitor, record, and report in accordance with the applicable parts of Condition 31.

21. Consistent with prudent utility practices, Permittee shall schedule one of its two routine EU ID 1 maintenance shutdowns (typically 2 to 8 weeks in duration) and its major maintenance shut-downs during the June, July, or August time period.



21.1 Compliance shall consist of an annual certification, in accordance with Condition 101, that the facility has met the requirements of Condition 21.


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22. Permittee shall install, certify, and operate, a continuous emission monitoring system on the EU ID 2 exhaust duct to measure and record the opacity, sulfur dioxide, oxides of nitrogen, and oxygen or carbon dioxide of emissions discharged to the atmosphere.


[AQC Permit #9431-AA001, Conditions 11, 13, 14, 15, and Exhibit D]

22.1 Monitor, record, and report in accordance with the applicable parts of Conditions 31, 54 and 55.

23. Permittee shall install and operate, an “as fired” fuel monitoring system upstream of the EU ID 2 coal pulverizers meeting the requirements of 40 C.F.R. 60, Appendix A, Method 19 to determine potential sulfur dioxide emissions of the EU ID 2 system. Permittee shall analyze the fuel sulfur content of composite samples monthly.



23.1 Monitor, record, and report in accordance with the applicable parts of Conditions 31, 54 and 55.

24. Permittee shall not request from the Department amendments to this permit, which would result in calendar year emission levels which would exceed 1,439 tpy for NOx or 721 tpy for SO2 for the combined operation of EU ID(s) 1 and 2.



25. If the EU ID 2 demonstration technology successfully reduces emissions as expected, Permittee shall request from the Department immediately, upon the completion of the demonstration test phase, through an application for amendment to this permit, reductions in the SO2 and /or NOX calendar year emissions limits to reflect achieved calendar year emission levels while allowing for reasonable operational variability. In addition, Permittee shall, in applications for permit renewals from the Department, continue to seek lower calendar year emission limits representative of achieved calendar year emission levels allowing for reasonable operational variability.





Page 19 of 74

26. If EU IDs 1 and/or 2 are operating and generating a NOX or other pollutant plume (exclusive of water vapor, steam, and ice crystal plumes) or a sulfate or other pollutant haze which impairs visibility and which is reasonably attributable to the operation of EU ID(s) 1 and/or 2, and is observed or otherwise detected within Denali National Park and Preserve (DNPP) boundaries by observers trained in pollutant plume and haze identification, Permittee shall, upon notification by National Park Service (NPS) or an order by the Department, immediately implement the procedures as follows:



26.1 All notifications of plume or haze observation or detection reasonably attributable to the operation of EU IDs 1 and/or 2 shall be relayed to the Permittee by the Park Superintendent or his or her designated representative.

26.2 The Park Superintendent or his or her designated representative shall notify Permittee’s Healy Plant Superintendent by telephone of plume or haze observation or detection, which is reasonably attributable to the operation of EU ID(s) 1 and/or 2 if the Park Superintendent determines that the report of such plume or haze observation or detection is credible.

26.3 Upon receipt of a notification of plume or haze observation or detection, Permittee will investigate the situation and proceed within 90 minutes of notification as follows:

a. If the Permittee concurs with the NPS determination in Condition 26.2 above, Permittee will reduce the combined emissions from EU IDs 1 and/or 2 to the level of EU ID 1 emissions prior to construction of EU ID 2 (approximately 200 lb/hour NOx and 150 lb/hour SO2) for a minimum of twelve (12) hours. This period of time will be extended for additional twelve (12) hour periods by mutual agreement of the parties, as defined in this condition, if the plume and/or haze persist, or conditions conducive to plume and/or haze formation persist. At any time during this period of reduced emissions, Permittee may resume full operations upon a determination, by the mutual agreement of the parties, as defined in this condition, that the plume and/or haze is no longer detectable and conditions conducive to plume and/or haze formation no longer exist. The phrase “by mutual agreement of the parties,” as used in this condition, means that Permittee’s Healy Plant Superintendent and the Park Superintendent, or their designated representatives, will discuss the issue requiring decision and undertake to reach agreement on the decision; if such decision cannot be agreed upon, Permittee may proceed to resume operations, and both parties will keep a record of the disagreement.

b. If Permittee does not concur with the Park Superintendent’s determination in Condition 26.2 above within 90 minutes or if the Park Superintendent does not concur with Permittee’s decision to resume operations in Condition 26.3a above, the Park Superintendent or his or her designated representative may notify air quality control personnel in the Department. The Department may then order Permittee to reduce the combined emissions as set forth in


Page 20 of 74

Condition 26.3a above if, after an opportunity for consultation with Permittee and the Park Superintendent, the Department concurs with the NPS determination based on an observation or detection made or confirmed by appropriately trained person or persons. Because this process depends on prompt decision-making and communication, telephone transactions are contemplated.

c. For purposes of any order issued under Condition 26.3b above, Permittee hereby waives rights to advance notice and opportunity for hearing provided by AS 46.03.850 (Compliance Orders) and stipulates to the imposition of any emergency order under AS 46.03.820.

26.4 In emergency conditions (defined as the loss of a significant portion of Permittee’s generating resources and/or the Alaska Intertie), Permittee will undertake the reductions in Condition 26.3a when the emergency conditions end.

27. Permittee shall provide reasonable technical and administrative support for any related ongoing studies that the US Department of Energy and the US Department of the Interior agree to pursue.




28. At the request of the NPS, Permittee shall provide NPS with fly ash and slag ash, as available, FOB Healy plant site, at no charge.




29. The Permittee shall comply with its obligations as described by the provisions of Healy Clean Coal Project Memorandum of Agreement, Section III and Addendum No. 1.



29.1 Compliance shall consist of an annual certification, in accordance with Condition 101, that the facility has met the applicable requirements of Condition 29.


Page 21 of 74

30. Each continuous emission monitoring system (CEMS) required under this permit must be installed, maintained, operated, and calibrated as specified in the applicable Performance Specification set out in Title 40 Code of Federal Regulations Part 60, Appendix B when the monitored emission unit is operating. A continuous emission monitoring system quality assurance plan must be developed and approved for each monitor required by this permit, conforming with Part 40 C.F.R. 60 Appendix F, and The Quality Assurance Handbook for Air Pollution Measurement Systems Volume Ill, (EPAJ600/4-77-027b). An alternate emission monitoring plan may be proposed if it can be shown to ensure continuous compliance.


[AQC Permit #9431-AA001, Exhibit D]


31. The Permittee shall monitor, record, and report according to Condition 100 the following information:

[18 AAC 50.040(j) and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a), (c)(6)]

[AQC Permit #9431-AA001, Exhibits C & D]

31.1 For EU ID 1:

a. Measure SO2 emissions continuously, and record the 60-minute average and three hour average SO2 emission concentration uncorrected and corrected to either 12.5% CO2 or 7% O2 in accordance with 40 C.F.R. Part 60, Appendix A, Method 19.

b. Calculate the 60-minute average SO2 emission rates based on the methodology set out in 40 C.F.R. 60, Appendix A, Method 19, and the Permittee’s CEMS operation and maintenance plan.

c. Calculate and record the 3-hour and 24-hour SO2 emissions rates on a calendar day basis.

d. Record and report monthly emissions of SO2 to the nearest 0.1 ton.

e. Record the date, time, duration, and average SO2 emission rate for any period exceeding 258 lb/hr for a 24-hour or greater averaging period, or 367 lb/hr for a 3-hour or greater averaging period. For the 3-hour averaging period, also record the SO2 concentration.

f. Attach to the facility operating report in Condition 100, a list of excess SO2

emissions with the date, time, duration, and average SO2 emission rate for any period exceeding an average 258 lb/hr for 24-hours or more, and for any period exceeding an average 367 lb/hr for 3-hours or more.

g. Measure and record the 60-minute average emission rate of NOX. Report monthly emissions to the nearest 0.1 ton.


Page 22 of 74

h. Measure and record the one-minute average opacity. Report the times, opacities, cumulative duration represented for all readings exceeding 20%

(i) when the cumulative duration is greater than three minutes in an hour, except

(ii) during startup, shutdown, soot blowing, grate cleaning and other routine maintenance activities specified in Condition 39.2c, report when the cumulative duration exceeding 20% is greater than six minutes in an hour.

31.2 For EU ID 2:

a. Measure and record the 6-minute average opacity. Report the time, duration, and average opacity for any period exceeding 20% for 6 minutes, and the time, duration, and average opacity for any period exceeding 27% for six minutes or more per hour.

b. Measure and record the 60-minute average emission rate of NOx. Report for each operating date the average daily NOx emission rate and 30-day rolling average (in lb/MMBtu). Report monthly emission to the nearest 0.1 ton.

c. Measure SO2 emissions continuously and record the three hour average SO2 emission concentration uncorrected and corrected to either 12.5% CO2 or 7% O2 in accordance with 40 CFR 60, Appendix A, Memo 19. Measure and record the 60-minute average emission rate of SO2. Report for each operating date the average daily SO2 emission rate (in lb/MMBtu) and the percent reduction of the potential combustion concentration of SO2 and the 30- day rolling averages. Report monthly emissions to the nearest 0.1 ton. Report date, time, duration, and average SO2 concentration for any period exceeding 0.10 lb/MMBtu or 65.8 lb/hr for 3 hours or more.

d. Measure and record the 60-minute average stack gas concentration of oxygen or carbon dioxide.

e. Measure and record the 60-minute average feed rate for coal and fuel oil. Report the amount of coal and fuel combusted during each day the emission unit operates.

f. Measure and record the 60 minute average emission rate of CO. Report monthly emissions to the nearest 0.1 ton.

31.3 For EU ID(s) 1 and 2, conduct a proximate and an ultimate coal analysis quarterly, including a trace component analysis, by any acceptable method of analysis and report the concentrations semi-annually. The analysis shall include fluorine and chlorine content.

31.4 For EU ID 2, conduct a beryllium analysis quarterly and report the concentrations semi-annually.


Page 23 of 74

32. Permittee shall submit a Quality Assurance Plan to the Department for each continuous emission monitoring system, as described in Condition 30.



33. Permittee will be required to reduce water emissions if the Department, in its sole discretion, determines that ice fog conditions exist at the source, which warrant the reduction. In no event shall the emissions create a public nuisance.


[18 AAC 50.080 1/18/1997]

33.1 Compliance shall consist of an annual certification, in accordance with Condition 101, that the source did not cause ice fog conditions requiring reduction.

34. Permittee shall comply with all parts of the visibility monitoring plan that was submitted in August 1994.




35. Permittee shall comply with all parts of the air quality monitoring plan that was submitted in July 1994, except for the PM-10 monitoring requirements.


[AQC Permit #9431-AA001, Condition 27 and Construction Permit #9831-AC018, Condition 22]


36. Permittee shall minimize fugitive particulate matter from the Haul Road identified as EU ID 11 as follows:

[AQC Permit #9431-AA001, Condition 25 (1st) and (2nd)] [Letter from John Kuterbach to Henrik Wessel, 6/16/03]

36.1 Clean the paved roads as needed to prevent fugitive emissions, and

36.2 Continue to apply the other PM-10 control measures applicable to the facility.

36.3 Compliance shall consist of an annual certification, in accordance with Condition 101, that the facility has met the requirements of Conditions 36.1 and 36.2.


Page 24 of 74

37. Permittee shall maintain the existing wind fence around the coal storage pile, EU ID 12. [18 AAC 50.040(j) and 18 AAC 50.326(j)]

[40 C.F.R. 71.6(a)] [AQC Permit #9431-AA001, Condition 24]

37.1 Compliance shall consist of an annual certification, in accordance with Condition 101, that the facility maintained the wind fence around the coal storage pile.

Insignificant Emission Units

38. For emission units at the stationary source that are insignificant as defined in 18 AAC 50.326(d)-(i) that are not listed in this permit, the following apply:

38.1 Opacity Standard. The Permittee shall not cause or allow visible emissions, excluding condensed water vapor, emitted from an industrial process, fuel-burning equipment, or an incinerator to reduce visibility through the exhaust effluent by more than 20 percent averaged over any six consecutive minutes.

[18 AAC 50.050(a) & 50.055(a)(1)]

38.2 Particulate Matter Standard. The Permittee shall not cause or allow particulate matter emitted from an industrial process or fuel-burning equipment to exceed 0.05 grains per cubic foot of exhaust gas corrected to standard conditions and averaged over three hours.

[18 AAC 50.055(b)(1)]

38.3 Sulfur Emissions Standard. The Permittee shall not cause or allow sulfur compound emissions, expressed as SO2, from an industrial process or fuel-burning equipment, to exceed 500 ppm averaged over three hours.

[18 AAC 50.055(c)]

38.4 General MR&R for Insignificant Emission Units.

a. The Permittee shall submit the compliance certifications of Condition 101 based on reasonable inquiry;

b. The Permittee shall comply with the requirements of Condition 78;

c. The Permittee shall report in the operating report required by Condition 100 if an emission unit is insignificant because of actual emissions less than the thresholds of 18 AAC 50.326(e) and actual emissions become greater than any of those thresholds;

d. No other monitoring, recordkeeping or reporting is required.

[18 AAC 50.346(b)(4)]


Page 25 of 74

Section 4. Conditions for Coal-Fired Boilers, Including Standard Operating Conditions for Boilers in Operation before July 1972.

EU ID 1 and 2

39. Coal Fired Boiler Visible Emissions. The Permittee shall not cause or allow visible emissions, excluding condensed water vapor, emitted from EU ID 2 listed in Table A to reduce visibility through the exhaust effluent by more than 20 percent averaged over any six consecutive minutes.

The Permittee shall not cause or allow visible emissions, excluding condensed water vapor, emitted from EU ID 1 listed in Table A to reduce visibility through the exhaust effluent by more than 20 percent for more than three minutes in any one hour. As an alternative for EU ID 1, the Permittee shall not cause or allow visible emissions to reduce visibility through the exhaust effluent by more than 20 percent for more than six minutes in any one hour, provided:


[18 AAC 50.055(a)(1) & 50.055(a)(9)]

a. the visible emissions are caused by startup, shutdown, soot blowing, grate cleaning, or other routine maintenance activities specified in Condition 39.2c;

b. the Permittee monitors visible emissions by continuous opacity monitoring instrumentation that conforms to the requirements set out in Conditions 39.2a and 39.2b.

39.1 Coal Fired Boiler Visible Emissions Monitoring. Monitor visible emissions from EU IDs 1 and 2 as required in Conditions 19 and 22.

39.2 Coal Fired Boiler Visible Emissions Monitoring – Procedures for Operation of a COMS. The following procedure applies to monitoring visible emissions using a Continuous Opacity Monitoring System (COMS):

[18 AAC 50.040(j); 18 AAC 50.326(j) and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(i)]

a. The COMS must meet the performance specifications in 40 C.F.R. 60, Appendix B, Performance Specification 1, adopted by reference in 18 AAC 50.040(a);

b. Operate and maintain the COMS in accordance with the manufacturer’s written requirements and recommendations;

c. Except during COMS breakdowns, repairs, calibration checks, and zero and upscale adjustments, complete one cycle of sampling and analyzing for each successive 10-second period of emission unit operation; from this data, calculate and record the average opacity for each successive one-minute period;


Page 26 of 74

d. At least once daily, conduct a zero and upscale check in accordance with 40 C.F.R. 60.13(d), adopted by reference in 18 AAC 50.040(a), and a written procedure; adjust whenever the zero or upscale drift exceeds four percent opacity in a 24-hour period;

39.3 Conduct performance audits as follows:

a. For a COMS that was new, relocated, replaced, or substantially refurbished on or after April 9, 2001, perform an audit according to the requirements in Section 5 that includes the following elements as described in the Department's Performance Audits for COMS, adopted by reference in 18 AAC 50.030, at least once in each 12 months:

(i) optical alignment;

(ii) zero and upscale response assessment;

(iii) zero compensation assessment;

(iv) calibration error check; and

(v) zero alignment assessment;

b. For a COMS that was new, relocated, replaced, or substantially refurbished before April 9, 2001, perform the same audits required under Condition 39.3a, except that Conditions 39.3a(i) through 39.3a(iv) must be performed at least quarterly; this frequency may be reduced if

(i) the Permittee demonstrates, by applying measurable criteria to the results of quarterly audits, that quarterly audits are not necessary; and

(ii) the Department gives written approval for the reduction in frequency.

39.4 If any of the COMS on the coal-fired boilers, EU IDs 1 or 2, is out of service for more than 24 hours, or the COMS failed the performance audit, then the Permittee shall use the visible emissions monitoring described in Condition 2 immediately.

39.5 Coal Fired Boiler Visible Emissions Reporting and Recordkeeping: EU IDs 1 and 2 listed in Table A are subject to the following VE recordkeeping and reporting requirements:

[18 AAC 50.040(j); 18 AAC 50.326(j) and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(ii) & (iii)]

a. Maintain records of all calculated one-minute average opacity values for COMS and records of the COMS performance audits required under Condition 39.3, according to the requirements of Condition 95.

b. If any of the COMS is malfunctioning or non-operable for three or more consecutive days, the Permittee shall notify the Department by telephone or in writing on the fourth day, indicating the cause of failure and anticipated time required to repair or replaced the instrument.


Page 27 of 74

c. For EU ID 1, report a violation of the emission standard in Condition 39 by filing an Excess Emission Notification Form under Condition 99 if the total number of one-minute values that exceed 20% opacity is greater than three during any given hour when the boiler is not undergoing startup, shutdown, soot blowing, grate cleaning, or other routine maintenance activities.

d. For EU ID 1, report a violation of the emission standard in Condition 39 by filing an Excess Emission Notification Form under Condition 99 if the total number of one-minute values that exceed 20% opacity is greater than six during any given hour when the boiler is undergoing startup, shutdown, soot blowing, grate cleaning, or other routine maintenance activities.

e. For EU ID 2, report a violation of the emission standard in Condition 39 by filing an Excess Emission Notification Form under Condition 99 if visible emissions exceed a six-minute average of 20%.

f. For the NSPS standard, also notify the Department, within 24 hours of any change in operating conditions which results in visible emissions from EU ID 2 exceeding 20% opacity for two or more 6-minute averages in any hour, or exceeding 27% for any 6-minute average. The notification must include the nature of the occurrence, the expected duration, the steps taken to minimize emissions and avoid recurrence, and a general description of the weather. Permittee shall submit a written report to the Department summarizing the required information by this Condition 39.5f for each event which occurred during each calendar month, by the fifteenth day of the following month.

[AQC Permit #9431-AA001 Condition 39, Condition 40, and Exhibit D] [Construction Permit #9831-AC018 Condition 26.1]

40. Coal Fired Boiler Particulate Matter (PM). EU IDs 1 and 2 are subject to the following particulate matter standards:

40.1 The Permittee shall not cause or allow particulate matter (PM) emitted from EU IDs 1 to exceed 0.05 grains per cubic foot of exhaust gas corrected to standard conditions and averaged over three hours.

40.2 The Permittee shall not cause or allow particulate matter (PM) emitted from EU IDs 2 to exceed 0.05 grains per cubic foot of exhaust gas corrected to standard conditions and averaged over three hours.

[18 AAC 50.055(b)(1) & 50.055(b)(2)(A)] [AQC #9431-AA001, Exhibit B, and construction permit 9831-AC018 Condition 23]

40.3 The Permittee shall not cause or allow PM emitted from EU ID 2 to exceed 0.020 lb/MMBtu, hourly average (13.2 lb/hr at full load).

[18 AAC 50.055(b)(2)] [AQC #9431-AA001, Exhibit B]

40.4 Monitor, record and report in accordance with Conditions 40.5 through 40.7.


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40.5 Coal Fired Boiler PM Monitoring and Recordkeeping. The Permittee shall do the following:

[18 AAC 50.040(j), 18 AAC 50.326(j), and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(i) & (ii)]

a. At least once every 12 months, for each boiler that has operated 90 days or more during that period, inspect the exhaust duct work and the internal components of the dust collector for the presence of leaks; prior to restarting the boiler, repair all leaks in the exhaust ductwork and all leaks that would allow dirty gas to pass into the clean gas side of the dust collector;

b. Conduct source tests for particulate matter as follows:

(i) Conduct the tests and report the results in accordance with Section 8. For tests required under Condition 40.5b(ii), submit the test plan required by Condition 91 at least 60 days before the deadline for conducting the test;

(ii) Conduct an initial test on EU ID 1 within 8760 operating hours or 24 months, whichever is sooner, after issuance of Permit No. AQ0173TVP02. Conduct an initial test on EU ID 2 within 8760 operating hours or 24 months, whichever is sooner, after the initial startup of EU ID2 under Permit No. AQ0173TVP02;

(iii) Conduct additional tests on each boiler within 8760 operating hours of the previous test;

40.6 Compliance Assurance Monitoring for Control of Particulate Matter (40 CFR 64). The Permittee shall comply with Conditions 40.6a through 40.6d for Compliance Assurance Monitoring consistent with 40 C.F.R., Part 64 for EU IDs 1 and 2 to monitor compliance of particulate emissions with the limits in Condition 40 and Table B, and for EU ID 2, Condition 50.1.

[40 C.F.R. 71.6(a)(3)(i)(A)] [40 C.F.R. 64.4 40 C.F.R. 64.3, 40 C.F.R. 64.6(b)]

a. Within 180 days of issuance of this permit, the Permittee shall submit a revised CAM plan for approval by the Department. The plan shall contain all required elements of 40 CFR 64.4 and proposed terms and conditions consistent with 40 CFR 64.6(c);

b. For EU IDs 1 and 2, the Permittee shall conduct an initial test under this permit, and subsequent performance testing both as described in 40 C.F.R. 60.48Da(o)(1), with the following exceptions:

(i) Testing for condensable particulate matter is not required, since the emission units are not subject to 40 C.F.R. 60.48 Subpart Da(o); and

(ii) Subsequent testing shall be conducted on each boiler within 8760 operating hours of the previous test, rather than annually. The Permittee shall submit source test plans and reports consistent with Section 8.


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c. On and after the initial performance test under Condition 40.6b, for EU IDs 1 and 2, the Permittee shall either,

(i) set the baseline opacity level and perform all monitoring, testing, record keeping, investigations, and corrective actions described in 40 C.F.R. 60.48Da(o)(2)(iii) through (vi), or

(ii) use a baghouse leak detection system as described in 40 C.F.R. 60.48Da(o)(4)(i) through (v), including all testing, record keeping, and corrective actions3.

d. To submit a new or revised CAM plan, the Permittee shall concurrently submit an application for a permit modification. The application shall include all required elements under 40 CFR 64.4 and proposed permit terms consistent with 40 CFR 64.6(c).

40.7 Coal Fired Boiler PM Reporting. The Permittee shall [18 AAC 50.040(j); 18 AAC 50.326(j) and 18 AAC 50.346(c)]

[40 C.F.R. 71.6(a)(3)(iii)]

a. Submit a report in accordance with Condition 99 whenever the results of a source test exceed the particulate matter emission limit.

b. Include in each operating report under Condition 100

(i) the results of each particulate matter source test;

(ii) the results of the quarterly proximate and ultimate coal analysis for coal burned in EU IDs 1 and 2, including the concentrations of chlorine and fluorine, and the concentration of beryllium in the coal burned in EU ID 2; and

(iii) a summary of excursions, investigation findings and corrective actions taken under Condition 40.4.

41. Sulfur Compound Emissions. The Permittee shall not cause or allow sulfur compound emissions, expressed as sulfur dioxide, from EU IDs 1 and 2 to exceed 500 ppm averaged over a period of three hours.

[18 AAC 50.055(c)]

41.1 Monitor, record and report in accord with Condition 31.

3 Subpart Da(o) is used as a reference methodology for 40 CFR 64 compliance only; the stationary source is not subject to 40 C.F.R. 60.48 Da(o).


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41.2 The Permittee shall determine the sulfur content of the “as fired” coal fuel monthly for EU IDs 1 and 2.

a. If valid representative results are not available from the supplier, analyze a representative sample of the fuel to determine the sulfur content using ASTM D2492-90 for coal, adopted by reference in 18 AAC 50.035(c), or another method approved in writing by the Department for coal or other fuels.

[18 AAC 50.040(j), 18 AAC 50.326(j), and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(ii)]

[Permit #9431-AA001 condition 8 and Exhibit C]

41.3 Coal Fired Boiler Sulfur Compound Emissions Record Keeping. Keep records of the sulfur dioxide concentration measured by the Condition 31 SO2 CEMS SO2 concentration averaged over three-hours.

[18 AAC 50.040(j), 18 AAC 50.326(j) and 18 AAC 50.346(c)] [40 C.F.R. 71.6(a)(3)(ii)]

41.4 Coal Fired Boiler Sulfur Compound Emissions Reporting. The Permittee shall [18 AAC 50.040(j), 18 AAC 50.326(j), and 18 AAC 50.346(c)]

[40 C.F.R. 71.6(a)(3)(iii)]

a. Submit a report in accordance with Condition 99 whenever

(i) a measured three-hour exhaust concentration is greater than 500 ppm.


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Section 5. Performance Audits for COMS

42. Performance audits. The following elements shall be included in performance audits for Continuous Opacity Monitoring Systems (COMS), unless the Department gives written approval for emission unit-specific audit procedures.

[18 AAC 50.030(9), 18 AAC 50.040(j), and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(3)(i)]

42.1 Optical Alignment Assessment. The status of the optical alignment of the monitor components shall be checked and recorded according to the procedures specified by the monitor manufacturer. Realign as necessary.

42.2 Zero and Upscale Response Assessment. The zero and upscale response errors shall be determined and recorded according to the calibration drift procedures of 8.1(4)(i) and (ii) in 40 C.F.R. 60, Appendix B, Performance Specification 1 (PS-1), adopted by reference in 18 AAC 50.040(a). The error is defined as the difference (in percent opacity) between the correct value and the observed value for the zero and high-level calibration checks.

42.3 Zero Compensation Assessment. The value of the zero compensation applied at the time of the audit shall be calculated as equivalent opacity, corrected to stack exit conditions as necessary, according to the procedures specified by the manufacturer. Record the compensation applied to the effluent recorded by the monitor system.

42.4 Calibration Error Check. Conduct a three-point calibration error test using three calibration attenuators that produce outlet path-length corrected, single-pass opacity values shown in ASTM D 6216-98, section 7.5, adopted by reference in 18 AAC 50.035(c). If the applicable limit is less than 10 percent opacity, use attenuators as described in ASTM D 6216-98, section 7.5 for applicable standards of 10 to 19 percent opacity. Confirm the external audit device produces the proper zero value on the COMS data recorder. Separately, insert each calibration attenuator (low, mid, and high-level) into the external audit device. While inserting each attenuator, (1) ensure that the entire light beam passes through the attenuator; (2) minimize interference from reflected light; and (3) leave the attenuator in place for at least two times the shortest recording interval on the COMS data recorder. Make a total of five non-consecutive readings for each attenuator. At the end of the test, correlate each attenuator insertion to the corresponding value from the data recorder. Subtract the single-pass calibration attenuator values corrected to the stack exit conditions from the COMS responses. Calculate the arithmetic mean difference, standard deviation, and confidence coefficient of the five measurements value using equations 1-3, 1-4, and 1-5 of PS-1. Calculate the calibration error as the sum of the absolute value of the mean difference and the 95 percent confidence coefficient for each of the three test attenuators using equation 1- 6 of PS-1. Report the calibration error test results for each of the three attenuators.


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42.5 Zero Alignment Assessment. Compare the COMS simulated zero to the actual clear path zero of the installation. The assessment may be conducted in conjunction with, but prior to, other performance audit elements.

a. Primary Zero Alignment Method. The primary zero alignment shall be performed under clear path conditions. This may be accomplished if the process is not operating and the monitor path length is free of particulate matter or the monitor may be removed from its installation and set up under clear path conditions. The absence of particulate matter shall be demonstrated prior to conducting the test at the installed site. No adjustment to the monitor is allowed other than the establishment of the proper monitor path length and correct optical alignment of the monitor components. Record the monitor response to a clear path condition and to the monitor's simulated zero condition as percent opacity corrected to stack exit conditions as necessary. For monitors with automatic zero compensation, disconnect or disable the zero compensation mechanism or record the amount of correction applied to the monitor's simulated zero condition. The response difference in percent opacity to the clear path and simulated zero conditions shall be recorded as the zero alignment error. Adjust the monitor's simulated zero device to provide the same response as the clear path condition. Restore the COMS to its operating mode.

b. Alternate Zero Alignment Method. Monitors capable of allowing the installation of an external, removable zero-jig may use the equipment for an alternative zero alignment provided that the zero-jig setting is established for the monitor path length and recorded for the specific COMS by comparison of the COMS responses to the installed zero-jig and to the clear path condition. The zero-jig is shown to be capable of producing a consistent zero response when it is repeatedly (i.e., three consecutive installations and removals prior to conducting the final zero alignment check) installed on the COMS. The zero-jig setting shall be permanently set at the time of the initial COMS zeroing to the clear path zero value and protected when not in use to ensure that the setting equivalent to zero opacity does not change. The zero-jig setting shall be checked and recorded prior to initiating the zero alignment. Emission unit owners and operators that employ a zero-jig shall perform a primary zero alignment audit once every three years.

c. Failure Criteria for Zero Alignment. The zero alignment is acceptable if the error at the simulated zero check is less than or equal to 2% opacity prior to adjustment (i.e. if the zero alignment error is 0% the analyzer does not need servicing solely based on this test).


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Section 6. Federal Requirements

Emission Units Subject to Federal New Source Performance Standards (NSPS), Subpart A

43. NSPS Subpart A Startup, Shutdown, & Malfunction Requirements. The Permittee shall maintain records of the occurrence and duration of any start-up, shutdown, or malfunction in the operation of EU IDs 2, 4, 6, 7, 9 and 10, any malfunctions of associated air-pollution control equipment, or any periods during which a continuous monitoring system or monitoring device for EU ID 2 is inoperative.

[18 AAC 50.040(a)(1)] [40 C.F.R. 60.7(b) & 60.11(c), Subpart A]

44. NSPS Subpart A Excess Emissions and Monitoring Systems Performance Report. Except as provided for in Condition 45, the Permittee shall submit to the Department and to EPA a written "excess emissions and monitoring systems performance report" (EEMSP)4 consistent with 40 C.F.R. 60.7(c) for emissions subject to limits under Conditions 50, 51 and 52.

The Permittee shall submit the EEMSP reports to EPA quarterly, except that the Permittee may reduce the frequency to semiannually if the conditions of 40 C.F.R. 60.7(e)(1) and (e)(2) are met. The reporting frequency will automatically revert to quarterly if emissions exceed a limit as described above in this condition. The Permittee may again request the Administrator for reduced frequency after demonstrating compliance for another full year. The report shall be postmarked no later than 30 days after the end of the reporting period.

Written reports of excess emissions shall include the following information:

[18 AAC 50.040(a)(1)] [40 C.F.R. 60.7(c) & (e), Subpart A]

44.1 The magnitude of excess emissions computed in accordance with Condition 49.3, any conversion factors used, the date and time of commencement and completion of each time period of excess emissions, and the process operating time during the reporting period.

[40 C.F.R. 60.7(c)(1), Subpart A]

44.2 Identification of each period of excess emissions that occurred during startup, shutdown, and malfunction of EU ID 2, the nature and cause of any malfunction, and the corrective action taken or preventative measures adopted.

[40 C.F.R. 60.7(c)(2), Subpart A]

44.3 The date and time identifying each period during which a Continuous Monitoring System (CMS) was inoperative except for zero and span checks and the nature of any repairs or adjustments.

[40 C.F.R. 60.7(c)(3), Subpart A]

44.4 A statement indicating whether or not any excess emissions occurred or the CMS was inoperative, repaired, or adjusted at any time during the reporting period.

[40 C.F.R. 60.7(c)(4), Subpart A]

4 The federal EEMSP report is not the same as the State excess emission report required by Condition 99.


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45. NSPS Subpart A Summary Report Form. The Permittee shall submit to the Department and to EPA one "summary report form5" in the format shown in Figure 1 of 40 C.F.R. 60.7 for each pollutant monitored for EU ID 2 as follows:

[18 AAC 50.040(a)(1)] [40 C.F.R. 60.7(d), Subpart A]

45.1 If the total duration of excess emissions for the reporting period is less than one percent of the total operating time for the reporting period and CMS downtime for the reporting period is less than five percent of the total operating time for the reporting period, submit a summary report form instead of the EEMSP report described in Condition 44, otherwise

[40 C.F.R. 60.7(d)(1), Subpart A]

45.2 Submit a summary report form along with the EEMSP described in Condition 44. [40 C.F.R. 60.7(d)(2), Subpart A]

46. NSPS Subpart A Good Air Pollution Control Practice. At all times, including periods of startup, shutdown, and malfunction, the Permittee shall, to the extent practicable, maintain and operate EU IDs 2, 4, 6, 7, 9 and 10 including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. The Administrator will determine whether acceptable operating and maintenance procedures are being used based on information available to the Department which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance records, and inspections of EU ID(s) 2, 4, 6, 7, 9, and 10.

[18 AAC 50.040(a)(1)] [40 C.F.R. 60.11(d), Subpart A]

47. NSPS Subpart A Credible Evidence. For the purpose of submitting compliance certifications or establishing whether or not the Permittee has violated or is in violation of the standards set forth in Conditions 50, 51, 52, 58, 59, 60 and 64, nothing in 40 C.F.R. Part 60 shall preclude the use, including the exclusive use, of any credible evidence or information relevant to whether EU IDs 2, 4, 6, 7, 9, and 10 would have been in compliance with applicable requirements of 40 C.F.R. Part 60 if the appropriate performance or compliance test or procedure had been performed.

[18 AAC 50.040(a)(1)] [40 C.F.R. 60.11(g), Subpart A]

48. NSPS Subpart A Concealment of Emissions. The Permittee shall not build, erect, install, or use any article, machine, equipment or process, the use of which conceals an emission which would otherwise constitute a violation of a standard set forth in Conditions 50, 51, 52, 58, 59, 60 and 64. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard that is based on the concentration of a pollutant in the gases discharged to the atmosphere.

[18 AAC 50.040(a)(1)] [40 C.F.R. 60.12, Subpart A]

5 See Summary Report form in Attachment A of the Statement of Basis.


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49. NSPS Subpart A, Monitoring. For a Continuous Monitoring System (CMS) required under Conditions 20 and 54, the Permittee shall:

[18 AAC 50.040(a)(1)] [40 C.F.R. 60.13(a) Subpart A]

49.1 Check the zero (or low level value between zero and 20 percent of span value) and span (50 to 100 percent of span value) calibration drifts at least once daily in accordance with 40 C.F.R. 60.13(d).

[40 C.F.R. 60.13(d)(1), Subpart A]

49.2 Except for system breakdowns, repairs, calibration checks, and zero and span adjustments required under Condition 49.1, keep all CMS's in operation continuously and as follows:

[40 C.F.R. 60.13(e), Subpart A]

a. for a Continuous Opacity Monitor (COMs), complete a minimum of one cycle of sampling and analyzing for each successive 10-second period and one cycle of data recording for each successive six-minute period; otherwise

[40 C.F.R. 60.13(e)(1), Subpart A]

b. complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.

[40 C.F.R. 60.13(e)(2), Subpart A]

49.3 Reduce data in accordance with: [40 C.F.R. 60.13(h), Subpart A]

a. Reduce all data to 6-minute averages and for continuous monitoring systems other than opacity to 1-hour averages for time periods as defined in 40 C.F.R. 60.2. Six-minute opacity averages shall be calculated from 36 or more data points equally spaced over each 6-minute period. For continuous monitoring systems other than opacity, 1-hour averages shall be computed from four or more data points equally spaced over each 1-hour period.

b. Do not include data recorded during periods of CMS breakdowns, repairs, calibration checks, and zero and span adjustments in the data averages computed under this condition.

c. Convert all excess emission into units of the standard used in Conditions 51 and 52, after conversion the Permittee may round data to the same number of significant digits as used in the condition.

d. The Permittee may use an arithmetic or integrator average of all data, and record data in reduced or non-reduced form (e.g. ppm pollutant percent O2 or ng/J of pollutant).


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Electric Utility Steam Generating Units Subject to NSPS Subpart Da

EU ID 2

50. NSPS Subpart Da PM Standard. On and after the date on which the initial performance test required to be conducted under 40 C.F.R. 60.8 is completed, the Permittee shall not cause to be discharged into the atmosphere from EU ID 2 any gases which:

50.1 contain particulate matter in excess of 13 ng/J (0.03 lb/MM Btu) heat input;

50.2 contain particulate matter in excess of 1 percent of the potential combustion concentration (99 percent reduction) when combusting solid fuel; or

50.3 exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity.

[40 C.F.R. 60.42Da]

51. NSPS Subpart Da Sulfur Standard. On and after the date on which the initial performance test required to be conducted under 40 C.F.R. 60.8 is completed, the Permittee shall not cause or allow to be discharged into the atmosphere from EU ID 2 any gases which contain sulfur dioxide in excess of:

51.1 520 ng/J (1.20 lb/MM Btu) heat input and 10 percent of the potential combustion concentration (90 percent reduction), or

51.2 30 percent of the potential combustion concentration (70 percent reduction, when emissions are less than 260 ng/J (0.60 lb/MM Btu) heat input.

Compliance with the emission limitation and percent reduction requirements under this section are both determined on a 30-day rolling average basis.

[40 C.F.R. 60.43Da(a) & (g)]

52. NSPS Subpart Da Nitrogen Oxides Standard. On and after the date on which the initial performance test required to be conducted under 40 C.F.R. 60.8 is completed, the Permittee shall not cause or allow to be discharged into the atmosphere from EU ID 2 any gases which contain nitrogen oxides in excess of:

52.1 0.50 lb/MMBtu, based on a 30-day rolling average; and

52.2 35 percent of the potential combustion concentration (65 percent reduction). [40 C.F.R. 60.44Da]

53. NSPS Subpart Da Compliance Provisions. For EU ID 2:

53.1 Compliance with the PM emission limitation under Condition 50.1 constitutes compliance with the percent reduction requirement under Condition 50.2 for PM.

[40 C.F.R. 60.48Da(a)]

53.2 Compliance with the NOX emission limitation under Condition 52.1 constitutes compliance with the percent reduction requirements under Condition 52.2.

[40 C.F.R. 60.48Da(b)]


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53.3 The particulate matter emission standards under 40 C.F.R. 60.42Da and the nitrogen oxides emission standards under 40 C.F.R. 60.44Da apply at all times to EU ID 2 except during periods of startup, shutdown, or malfunction. The sulfur dioxide emission standards under 40 C.F.R. 60.43Da apply at all times except when both emergency conditions exist and the procedures under Condition 53.4 are implemented.

[40 C.F.R. 60.48Da(d)]

53.4 During emergency conditions in the principal company, EU ID 2 with a malfunctioning flue gas desulfurization system may be operated if SO2 emissions are minimized by:

a. Operating all operable flue gas desulfurization system modules, and bringing back into operation any malfunctioned module as soon as repairs are completed; and

b. Bypassing flue gases around only those flue gas desulfurization system modules that have been taken out of operation because they were incapable of any SO2 emission reduction or which would have suffered significant physical damage if they had remained in operation.

[40 C.F.R. 60.48Da(d)]

53.5 Compliance is determined by calculating the arithmetic average of all hourly emission rates from EU ID 2 for SO2 and NOX for the 30 successive boiler operating days, except for data obtained during startup, shutdown, malfunction (NOX only), or emergency conditions (SO2 only). Compliance with the percentage reduction requirement for SO2 is determined based on the average inlet and average outlet SO2 emission rates for the 30 successive boiler operating days.

[40 C.F.R. 60.48Da(g)]

53.6 If the Permittee has not obtained the minimum quantity of emission data as required under 40 C.F.R. 60.49Da, compliance of the affected facility with the emission requirements under Conditions 51 and 52 for the day on which the 30-day period ends may be determined by the Administrator by following the applicable procedures in 40 C.F.R. 60, appendix A, Method 19, section 7.

[40 C.F.R. 60.48Da(h)]

54. NSPS Subpart Da Emission Monitoring.

54.1 The Permittee shall install, calibrate, maintain and operate a continuous monitoring system for EU ID 2, and record the output of the system, for measuring the opacity of emissions discharged to the atmosphere in accordance with 40 C.F.R. 60.49Da(a).

54.2 The Permittee shall install, calibrate, maintain and operate a continuous monitoring system for EU ID 2, and record the output of the system, for measuring sulfur dioxide emissions, as follows:

a. Sulfur dioxide emissions are monitored at both the inlet and outlet of the sulfur dioxide control device.


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b. An "as fired" fuel monitoring system (upstream of coal pulverizers) meeting the requirements of Appendix, Method 19 may be used to determine potential SO2 emissions in place of a continuous sulfur dioxide emission monitor at the inlet to the sulfur dioxide control device as required under Condition 54.2a of this permit.

54.3 The Permittee shall install, calibrate, maintain and operate a continuous monitoring system for EU ID 2, and record the output of the system, for measuring NOx

emissions discharged to the atmosphere.

54.4 The Permittee shall install, calibrate, maintain and operate a continuous monitoring system for EU ID 2, and record the output of the system, for measuring the oxygen or CO2 content of the flue gases at each location where SO2 or NOX emissions are monitored.

54.5 The continuous monitoring systems under Conditions 54.2, 54.3, and 54.4 are operated and data recorded during all periods of operation of EU ID 2 including periods of startup, shutdown, malfunction or emergency conditions, except for continuous monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments. Monitoring shall be conducted in accordance with methods and procedures specified in 40 C.F.R. 60.49Da(f)-(m).

54.6 Conduct unit 2 emissions testing in accordance with Condition 40.5b . [40 C.F.R. 60.49Da 40CFR 71.6(a)(3)]

55. NSPS Subpart Da Reporting for EU ID 2

55.1 For sulfur dioxide, nitrogen oxides, and particulate matter emissions, the performance test data from the initial performance test and from the performance evaluation of the continuous monitors (including the transmissometer) are submitted to the EPA Administrator.

[40 C.F.R. 60.51Da(a)]

55.2 For sulfur dioxide and nitrogen oxides, the following information is reported to the EPA for each 24-hour period.

[40 C.F.R. 60.51Da(b)]

a. Calendar date.

b. The average SO2 and NOx emission rates (ng/J or lb/MM Btu) for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the emission standards; and, description of corrective actions taken.

c. Percent reduction of the potential combustion concentration of SO2 for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the standard; and, description of corrective actions taken.


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d. Identification of the boiler operating days for which pollutant or diluent data have not been obtained by an approved method for at least 75% of the hours of operation of the facility; justification for not obtaining sufficient data; and description of corrective actions taken.

e. Identification of the times when emissions data have been excluded from the calculation of average emission rates because of startup, shutdown, malfunction (NOx only), emergency conditions (SO2 only), or other reasons, and justification for excluding data for reasons other than startup, shutdown, malfunction, or emergency conditions.

f. Identification of "F" factor used for calculations, method of determination, and type of fuel combusted.

g. Identification of times when hourly averages have been obtained based on manual sampling methods.

h. Identification of the times when the pollutant concentration exceeded full span of the continuous monitoring system.

i. Description of any modifications to the continuous monitoring system which could affect the ability of the continuous monitoring system to comply with Performance Specifications 2 or 3.

55.3 If the minimum quantity of emission data as required by § 60.49Da is not obtained for any 30 successive boiler operating days, the following information obtained under the requirements of § 60.48Da(h) is reported to the Administrator for that 30-day period:

a. The number of hourly averages available for outlet emission rates (no) and inlet emission rates (ni) as applicable.

b. The standard deviation of hourly averages for outlet emission rates (so) and inlet emission rates (si) as applicable.

c. The lower confidence limit for the mean outlet emission rate (Eo*) and the upper confidence limit for the mean inlet emission rate (Ei*) as applicable.

d. The applicable potential combustion concentration.

e. The ratio of the upper confidence limit for the mean outlet emission rate (Eo*) and the allowable emission rate (Estd) as applicable.

[40 C.F.R. 60.51Da(c)]

55.4 If any standards under Condition 51 are exceeded during emergency conditions because of control system malfunction, the Permittee shall submit a signed statement:

[40 C.F.R. 60.51Da(d)]

a. Indicating if emergency conditions existed and requirements under Condition 53.4 were met during each period, and


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b. Listing the following information:

(i) Time periods the emergency condition existed;

(ii) Electrical output and demand on the owner or operator’s electric utility system and the affected facility;

(iii) Amount of power purchased from interconnected neighboring utility companies during the emergency period;

(iv) Percent reduction in emissions achieved;

(v) Atmospheric emission rate (ng/J) of the pollutant discharged; and

(vi) Actions taken to correct control system malfunction.

55.5 For any periods for which opacity, SO2 or NOX emissions data are not available, Permittee shall submit a signed statement indicating if any changes were made in operation of the emission control system during the period of data unavailability. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before and following the period of data unavailability.

[40 C.F.R. 60.51Da(f)]

55.6 The Permittee shall submit a signed statement indicating whether:

[40 C.F.R. 60.51Da(h)]

a. The required CEMS calibration, span, and drift checks or other periodic audits have or have not been performed as specified.

b. The data used to show compliance was or was not obtained in accordance with approved methods and procedures of this part and is representative of plant performance.

c. The minimum data requirements have or have not been met; or, the minimum data requirements have not been met for errors that were unavoidable.

d. Compliance with the standards has or has not been achieved during the reporting period.

55.7 For the purposes of the reports required under Condition 44, periods of excess emissions are defined as all 6-minute periods during which the average opacity exceeds the applicable opacity standards under Condition 50.3. Opacity levels in excess of the applicable opacity standard and the date of such excesses are to be submitted to the Administrator each calendar quarter.

[40 C.F.R. 60.51Da(i)]

55.8 The Permittee shall submit the written reports required under this section and subpart A to the Administrator semiannually for each six-month period. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period.

[40 C.F.R. 60.51Da(j)]


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55.9 The Permittee may submit electronic quarterly reports for SO2 and/or NOX and/or opacity in lieu of submitting the written reports required under Conditions 55.2 and 55.7. The format of each quarterly electronic report shall be consistent with conditions. The electronic report(s) shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a certification statement from the owner or operator, indicating whether compliance with the applicable emission standards and minimum data requirements of this subpart was achieved during the reporting period. Before submitting reports in the electronic format, the owner or operator shall coordinate with the permitting authority to obtain their agreement to submit reports in this alternative format.

[40 C.F.R. 60.51Da(k)]

Steam Generating Units Subject to NSPS Subpart Dc

EU ID 4

56. NSPS Subpart Dc Notification Requirement. The Permittee of each affected facility shall submit notification of the date of construction or reconstruction, anticipated startup, and actual startup, as provided by 40 C.F.R. 60.7 (Condition 43). This notification shall include:

[18 AAC 50.040(a)(2)(D)] [40 C.F.R. 60.48c(a), Subpart Dc]

56.1 The design heat input capacity of the affected facility and identification of fuels to be combusted in the affected facility.

[40 C.F.R. 60.48c(a)(1), Subpart Dc]

56.2 The annual capacity factor at which the owner or operator anticipates operating the affected facility based on all fuels fired and based on each individual fuel fired.

[40 C.F.R. 60.48c(a)(3), Subpart Dc]

57. NSPS Subpart Dc Fuel Consumption. For EU ID 4, the Permittee shall record the amounts of each fuel combusted during each day and maintain the records for a period of two years following the date of such record. As an alternative, the Permittee may elect to record and maintain records of the amount of each fuel combusted during each calendar month, or of each fuel delivered during each calendar month.

[18 AAC 50.040(a)(2)(D)] [40 C.F.R. 60.48c(g), Subpart Dc]

58. NSPS Subpart Dc Sulfur Standards. At all times, including periods of startup, shutdown, and malfunction, for EU ID 4 the Permittee shall either emit less than 0.5 lb. SO2/MMBtu of fuel combusted, or shall combust fuel oil that contains less than 0.5 percent sulfur by weight.

[18 AAC 50.040(a)(2)(D)] [40 C.F.R. 60.42c(d), Subpart Dc]


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58.1 Monitoring - Compliance with the emission limits or fuel oil sulfur limits shall be determined based on a certification from the fuel supplier.

[40 C.F.R. 60.42c(h) , 44c(h), &46c(e), Subpart Dc]

58.2 Recordkeeping and Reporting - The Permittee shall keep records and submit reports to EPA, as follows:

[40 C.F.R. 60.48c(d), (f), Subpart Dc] For Distillate Fuel Oil

a. Fuel supplier certification shall include the following information:

(i) the name of the oil supplier;

(ii) a statement from the oil supplier that the oil complies with the specifications under the definition of distillate oil in 40 C.F.R. 60.41c, and

(iii) the sulfur content of the oil. [40 C.F.R. 60.48c(f)(1), Subpart Dc]

b. Include

(i) the calendar dates covered in the reporting period;

(ii) 30-day average sulfur content (weight percent), calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of corrective actions taken; and

(iii) a certified statement signed by the owner or operator of the affected facility that the records of fuel supplier certifications submitted represent all of the fuel combusted during the reporting period.

[40 C.F.R. 60.48c(e)(1), (2), & (11), Subpart Dc]

c. The reporting period for the reports required under this Condition 58.2 is each six-month period. All reports shall be submitted to EPA and shall be postmarked by the 30th day following the end of the reporting period.

[40 C.F.R. 60.48c(j), Subpart Dc]

59. NSPS Subpart Dc PM Standards: At all times, except during periods of startup, shutdown, and malfunction, the Permittee shall not cause to be discharged into the atmosphere from EU ID 4 any gases that exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity.

The opacity standard of this condition applies at all times, except during periods of startup, shutdown, or malfunction.

[18 AAC 50.040(a)(2)(D)] [40 C.F.R. 60.43c(c) & (d), Subpart Dc]

59.1 Monitoring - Method 9 (6-minute average of 24 observations) shall be used for determining the opacity of stack emissions from EU ID 4.

[40 C.F.R. 60.45c(a)(8), Subpart Dc]


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59.2 The Permittee shall monitor compliance with Condition 59 using Conditions 8 - 10. [18 AAC 50.040(a)(2)(D), 50.326(j)]

[40 C.F.R. 60.47c(c) and 48c(f), 71.6(a)(3)]

59.3 Reporting – The Permittee shall

a. submit to EPA the performance test data from the initial and any subsequent performance tests;

[40 C.F.R. 60.48c(b), Subpart Dc]

b. submit excess emission reports for any excess emissions from EU ID 4 which occur during the reporting period.

[40 C.F.R. 60.48c(c), Subpart Dc]

59.4 Reporting. The reporting period for the reports required under Condition 59.3 is each six-month period. All reports shall be submitted to EPA and shall be postmarked by the 30th day following the end of the reporting period.

[40 C.F.R. 60.48c(j), Subpart Dc]

Non-Metallic Mineral Processing Subject to NSPS Subpart OOO

EU IDs 7 and 9

60. NSPS Subpart OOO Standards for Particulate Matter.

60.1 For EU ID 9, the Permittee shall not discharge into the atmosphere from any transfer point on belt conveyors or from any other affected facility, any stack emission which contains particulate matter in excess of 0.05 g/dscm (0.022 gr/dscf) and exhibits greater than 7 percent opacity.

[18 AAC 50.040(a)(2)(FF)] [40 C.F.R. 60.672(a)(1) and (a)(2), Subpart OOO]

60.2 For EU ID 9, the Permittee shall not discharge into the atmosphere from any crusher, at which a capture system is not used, fugitive emissions which exhibit greater than 15 percent opacity.

[18 AAC 50.040(a)(2)(FF)] [40 C.F.R. 60.672(c), Subpart OOO]

60.3 The building enclosing EU IDs 7 and 9 shall comply with the emission limits specified in 40 C.F.R. 60.672(e).

[18 AAC 50.040(a)(2)(FF)] [40 C.F.R. 60.672(e), Subpart OOO]

60.4 For EU IDs 7 and 9, the Permittee shall not cause to be discharged into the atmosphere from any baghouse that controls emissions from only an individual, enclosed storage bin, stack emissions which exhibit greater than 7 percent opacity.

[18 AAC 50.040(a)(2)(FF)] [40 C.F.R. 60.672(f), Subpart OOO]

61. Monitoring procedures:

61.1 For EU ID 7, determine compliance with Condition 60 in accordance with 40 C.F.R. 60.675(c)(2) and 40 C.F.R. 60.675(d).


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61.2 For EU ID 9, determine compliance with Condition 60 in accordance with 40 C.F.R. 60.675(a) and (b), and 40 C.F.R. 60.675 (c)(1), (c)(2), and (c)(4).

[40 C.F.R. 60.675, Subpart OOO; 40 C.F.R. 60.8, Subpart A; 40 C.F.R. 71.6(a)(3)(i)] [18 AAC 50.040(a)(2)(FF), 18 AAC 50.040(j), and 18 AAC 50.326(j)]

62. Recordkeeping procedures: For EU IDs 7 and 9, record all information required for reporting under Condition 63.

[40 C.F.R. 60.676, Subpart OOO; 40 C.F.R. 71.6(a)(3)(i)] [18 AAC 50.040(a)(2)(FF), 18 AAC 50.040(j), and 18 AAC 50.326(j)]

63. Reporting procedures:

63.1 For EU IDs 7 and 9, the Permittee shall submit written reports of performance test results in accordance with 40 C.F.R. 60.676(f).

[18 AAC 50.040(a)(2)(FF)] [40 C.F.R. 60.676(f), Subpart OOO]

63.2 Report any excess emissions, in accordance with Condition 99, whenever the emission limits of Condition 60 are exceeded.

[18 AAC 50.040(j) and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(3)(i)]

Coal Preparation Plants Subject to NSPS Subpart Y

EU IDs 6 and 10

64. NSPS Subpart Y PM Standards. On and after the date on which the initial performance test required to be conducted under 40 C.F.R. 60.8 is completed, for EU IDs 6 and 10 the Permittee shall not cause to be discharged into the atmosphere from any coal processing and conveying equipment, coal storage system, or coal transfer and loading system processing coal, gases which exhibit 20 percent opacity or greater.

[40 C.F.R. 60.252(c)]

64.1 Method 9 and the procedures in 40 C.F.R. 60.11 shall be used to determine opacity.

[40 C.F.R. 60.254(b)(2)]

64.2 Report any excess emissions, in accordance with Condition 99, whenever the emission limits of Condition 64 are exceeded.

[18 AAC 50.040(j) and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(3)(i)]

Emission Units/Stationary Sources Subject to Federal National Emission Standards for Hazardous Air Pollutants (NESHAPs) General Provisions

65. NESHAP Subpart A. The Permittee shall comply with the applicable requirements of 40 C.F.R 63 Subpart A in accordance with the provisions for applicability of Subpart A in Table 8 to Subpart ZZZZ, and with the provisions for applicability of Subpart A in Table 8 to Subpart JJJJJJ.

[18 AAC 50.040(c)(1)] [40 C.F.R. 63.6665, Subpart ZZZZ and 63.11235, Subpart JJJJJJ]


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Stationary Reciprocating Internal Combustion Engines Subject to 40 C.F.R. Part 63, Subpart ZZZZ (EU ID 5)

66. NESHAP Subpart ZZZZ. For EU IDs 5 and 11, the Permittee shall comply with applicable requirements for existing stationary compression ignition reciprocating internal combustion engines (RICE) located at an area source of HAPs no later than May 3, 2013.

[18 AAC 50.040(c)(23)] [40 C.F.R. 63.6595(a)(1), Subpart ZZZZ]

66.1 At all times, operate and maintain EU IDs 5 and 11, including any associated air pollution control and monitoring equipment, in a manner consistent with good air pollution control practices for minimizing emissions;

[18 AAC 50.040(c)(23)] [40 C.F.R. 63.6605, Subpart ZZZZ]

66.2 The Permittee must meet the following requirements for EU IDs 5 and 11:

a. Change oil and filter every 500 hours of operation or annually, whichever comes first;

b. Inspect the air cleaner every 1,000 hours of operation or annually, whichever comes first; and

c. Inspect all hoses and belts every 500 hours of operation or annually, whichever comes first and replace as necessary.

[18 AAC 50.040(c)(23)] [40 C.F.R. 63.6603(a) and Table 2.d(4), Subpart ZZZZ]

66.3 Minimize EU ID 5’s and 11’s time spent at idle during startup and minimize the engine’s startup time to a period needed for appropriate and safe loading of the engine, not to exceed 30 minutes.

[18 AAC 50.040(c)(23)] [40 C.F.R. 63.6625(h), Subpart ZZZZ]

66.4 The Permittee shall limit the operation of the emergency stationary RICE (EU IDs 5 and 11) to emergency situations and required testing and maintenance. The Permittee shall limit the operation of EU IDs 5 and 11 for operation and maintenance checks to 100 hours per calendar year. The Permittee shall limit any operation other than emergency operation, maintenance and testing, and operation in non-emergency situations to 50 hours per calendar year.

[18 AAC 50.040(c)(23)] [40 C.F.R. 63.6675 and 63.6640(f)(1)-(4), Subpart ZZZZ]

66.5 Recordkeeping. Keep records as required by 40 CFR 63.6655 for at least 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to 40 CFR 63.10(b)(1).

[18 AAC 50.040(c)(23)] [40 C.F.R. 63.6655, Subpart ZZZZ]


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66.6 Reporting. Submit semiannual compliance reports and annual operating reports to U.S. Environmental Protection Agency (EPA) Region 10 and the Department according to 40 CFR 63.6650.

[18 AAC 50.040(c)(23) & 50.326(j)] [40 C.F.R. 63.6605, Subpart ZZZZ]

66.7 Report under Condition 100 any deviation from an emission limitation or an operating limitation during the reporting period in addition to reporting under 40 CFR 63.6650.

[18 AAC 50.040(c)(23) & 50.326(j)] [40 C.F.R. 63.6605, Subpart ZZZZ]

66.8 Report in the operating report under Condition 100 the calendar year operating hours of EU IDs 5 and 11 recorded under Condition 66.4.

[18 AAC 50.040(j) & 50.326(j)(4)] [40 C.F.R. 71.6(a)(3)(i)(B)]

NESHAP for Area Sources: Industrial, Commercial, and Institutional Boilers, 40 C.F.R. 63, Subpart JJJJJJ (EU IDs 3 and 4)

67. Hazardous Air Pollutant Area Source/Major Source Status. Unless and until the testing and analysis required by Condition 82 show that the Healy Power Plant is a major source of hazardous air pollutants, for EU IDs 3 and 4 the Permittee shall comply with Conditions 67.1 thorough 67.2. If that testing and analysis shows that the Healy Power Plant is a major source of Hazardous Air Pollutants, the Permittee need not comply with Conditions 67.1 - 67.2, but must instead comply with 40 C.F.R. 63, Subpart DDDDD for emission units 3 and 4.

[18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(1); 40 C.F.R. 63. Subparts DDDDD and JJJJJJ]

67.1 Management Practice Standard. For EU IDs 3 and 4, no later than March 21, 2012 the Permittee shall achieve and demonstrate compliance with the tune-up requirement in 40 C.F.R. 63, Subpart JJJJJJ Table 2, Item 3 as follows.

[18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(1) & (a)(3); 40 C.F.R. 63.11214(b), 63.11196(a)(1),

63.11201(b), 63.11210(c), 63.11223 & 63.11225]

(i) Tune-up. Conduct an initial and biennial tune-ups consistent with 40 C.F.R. 63.11223(a) and (b).

(ii) Notifications. Submit the following notifications to the Department:

(iii) As applicable, submit the notifications of 40 C.F.R. 63, Subpart A as listed in 40 C.F.R. 63.11225(a)(1).

(iv) Submit the Initial Notification as required in 40 C.F.R. 63.11225(a)(2).

(v) Submit the Notification of Compliance Status as described in 40 C.F.R. 63.11225(a)(4). Submit a signed statement in the Notification of Compliance Status report that indicates that the Permittee conducted a tune-up of the boiler.


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b. Reports. Prepare and submit a biennial compliance certification report as required by 40 C.F.R. 63.11225(b). Submit the Department copy of the biennial report with the operating permit compliance certification of Condition 101.6

c. Records. Keep records as required by 40 C.F.R. 63.11225(c) and (d).

67.2 Good Air Pollution Control Practice. At all times the Permittee shall operate and maintain EU IDs 3 and 4, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions, consistent with 40 C.F.R. 63.11205(a).

[18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(1); 40 C.F.R. 63.11205(a)]

6 40 C.F.R. 63.11225(b) requires the report to be submitted to the Department by March 15 if there are any permit deviations during the calendar year. The compliance certification report of Condition 101 is not required until March 31. However, this information is required to be reported sooner by Condition 99, Excess Emissions and Permit Deviations.


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Section 7. General Conditions

Standard Terms and Conditions

68. Each permit term and condition is independent of the permit as a whole and remains valid regardless of a challenge to any other part of the permit.

[18 AAC 50.326(j)(3) and 18 AAC 50.345(a) & (e)]

69. The permit may be modified, reopened, revoked and re-issued, or terminated for cause. A request by the Permittee for modification, revocation and re-issuance, or termination or a notification of planned changes or anticipated noncompliance does not stay any permit condition.

[18 AAC 50.326(j)(3) and 18 AAC 50.345(a) & (f)]

70. The permit does not convey any property rights of any sort, nor any exclusive privilege.

[18 AAC 50.326(j)(3)and 18 AAC 50.345(a) & (g)]

71. Administration Fees. The Permittee shall pay to the Department all assessed permit administration fees. Administration fee rates are set out in 18 AAC 50.400-405.

[18 AAC 50.326(j)(1), 18 AAC 50.400, 18 AAC 50.403, and 18 AAC 50.405] [AS 37.10.052(b) and AS 46.14.240]

72. Assessable Emissions. The Permittee shall pay to the Department an annual emission fee based on the stationary source’s assessable emissions as determined by the Department under 18 AAC 50.410. The assessable emission fee rate is set out in 18 AAC 50.410(b). The Department will assess fees per ton of each air pollutant that the stationary source emits or has the potential to emit in quantities greater than 10 tons per year. The quantity for which fees will be assessed is the lesser of

72.1 the stationary source's assessable potential to emit of 3,692 TPY; or

72.2 the stationary source’s projected annual rate of emissions that will occur from July 1 to the following June 30, based upon actual annual emissions emitted during the most recent calendar year or another 12-month period approved in writing by the Department, when demonstrated by

a. an enforceable test method described in 18 AAC 50.220;

b. material balance calculations;

c. emission factors from EPA’s publication AP-42, Vol. I, adopted by reference in 18 AAC 50.035; or

d. other methods and calculations approved by the Department. [18 AAC 50.040(j)(3), 18 AAC 50.326(j)(1), 18 AAC 50.035

and 18 AAC 50.346(b)(1)] 18 AAC 50.410; and 18 AAC 50.420]


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73. Assessable Emission Estimates. Emission fees will be assessed as follows:

73.1 no later than March 31 of each year, the Permittee may submit an estimate of the stationary source’s assessable emissions to ADEC, Air Permits Program, ATTN: Assessable Emissions Estimate, 410 Willoughby Ave., PO Box 1800, Juneau, AK 99811-1800; the submittal must include all of the assumptions and calculations used to estimate the assessable emissions in sufficient detail so the Department can verify the estimates; or

73.2 if no estimate is submitted on or before March 31 of each year, emission fees for the next fiscal year will be based on the potential to emit set forth in Condition 72.1.

[18 AAC 50.040(j)(3), 18 AAC 50.326(j)(1), 18AAC 50.346(b)(1), 18 AAC 50.410, and 18 AAC 50.420]

74. Good Air Pollution Control Practice. Except as noted in Condition 74d, the Permittee shall do the following for EU IDs 1, 3, 5 and 8:

a. perform regular maintenance considering the manufacturer’s or the operator’s maintenance procedures;

b. keep records of any maintenance that would have a significant effect on emissions; the records may be kept in electronic format; and

c. keep a copy of either the manufacturer’s or the operator’s maintenance procedures.

d. EU ID 5 is subject to this condition only until the applicable compliance date as set forth in Condition 66.

[18 AAC 50.030, 18 AAC 50.326(j)(3) and 18 AAC 50.346(b)(5)]

75. Dilution. The Permittee shall not dilute emissions with air to comply with this permit. Monitoring shall consist of an annual certification that the Permittee does not dilute emissions to comply with this permit.

[18 AAC 50.045(a), 18 AAC 50.040(j), and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)]

76. Reasonable Precautions to Prevent Fugitive Dust. A person who causes or permits bulk materials to be handled, transported, or stored, or who engages in an industrial activity or construction project shall take reasonable precautions to prevent particulate matter from being emitted into the ambient air.

[18 AAC 50.045(d), 18 AAC 50.040(e), 18 AAC 50. 326(j)(3), and 18 AAC 50.346(c)]

77. Stack Injection. The Permittee shall not release materials other than process emissions, products of combustion, or materials introduced to control pollutant emissions from a stack at an emission unit constructed or modified after November 1, 1982, except as authorized by a construction permit, operating permit, or air quality control permit issued before October 1, 2004.

[18 AAC 50.055(g), 18 AAC 50.040(j)(3), 18 AAC 50.326(j)(1)] [40 C.F.R. 71.6(a)]


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78. Air Pollution Prohibited. No person may permit any emission which is injurious to human health or welfare, animal or plant life, or property, or which would unreasonably interfere with the enjoyment of life or property.

[18 AAC 50.110, 18 AAC 50.040(e), 18 AAC 50.326(j)(3) and 18 AAC 50.346(a)] [40 C.F.R. 71.6(a)]

78.1 Monitoring, Record Keeping, and Reporting for Condition 78

a. If emissions present a potential threat to human health or safety, the Permittee shall report any such emissions according to Condition 99.

b. As soon as practicable after becoming aware of a complaint that is attributable to emissions from the stationary source, the Permittee shall investigate the complaint to identify emissions that the Permittee believes have caused or are causing a violation of Condition 78.

78.2 The Permittee shall initiate and complete corrective action necessary to eliminate any violation identified by a complaint or investigation as soon as practicable if

a. after an investigation because of a complaint or other reason, the Permittee believes that emissions from the stationary source have caused or are causing a violation of Condition 78; or

b. the Department notifies the Permittee that it has found a violation of Condition 78.

78.3 The Permittee shall keep records of

a. the date, time, and nature of all emissions complaints received;

b. the name of the person or persons that complained, if known;

c. a summary of any investigation, including reasons the Permittee does or does not believe the emissions have caused a violation of Condition 78; and

d. any corrective actions taken or planned for complaints attributable to emissions from the stationary source.

78.4 With each stationary source operating report under Condition 100, the Permittee shall include a brief summary report which must include

a. the number of complaints received;

b. the number of times the Permittee or the Department found corrective action necessary;

c. the number of times action was taken on a complaint within 24 hours; and

d. the status of corrective actions the Permittee or Department found necessary that were not taken within 24 hours.


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78.5 The Permittee shall notify the Department of a complaint that is attributable to emissions from the stationary source within 24 hours after receiving the complaint, unless the Permittee has initiated corrective action within 24 hours of receiving the complaint.

79. Technology-Based Emission Standard. If an unavoidable emergency, malfunction, or non-routine repair, as defined in 18 AAC 50.235(d), causes emissions in excess of a technology-based emission standard7 listed in Condition(s) 50, 51, 52, 58, 59, 60, 64 and 81 (refrigerants), the Permittee shall take all reasonable steps to minimize levels of emissions that exceed the standard. Excess emissions reporting under Condition 99 requires information on the steps taken to minimize emissions. Monitoring of compliance for this condition consists of the report required under Condition 99.

[18 AAC 50.235(a), 18 AAC 50.326(j)(4) and 18 AAC 50.040(j)(4)] [40 C.F.R. 71.6(c)(6)]

80. Asbestos NESHAP. The Permittee shall comply with the requirements set forth in 40 C.F.R. 61.145, 61.150, and 61.152 of Subpart M, and the applicable sections set forth in 40 C.F.R. 61, Subpart A and Appendix A.

[18 AAC 50.040(b)(1) & (2)(F), and 18 AAC 50.326(j)] [40 C.F.R. 61, Subparts A & M, and Appendix A]

81. Refrigerant Recycling and Disposal. The Permittee shall comply with the standards for recycling and emission reduction of refrigerants set forth in 40 C.F.R. 82, Subpart F.

[18 AAC 50.040(d) & 18 AAC 50.326(j)] [40 C.F.R. 82, Subpart F]

NESHAPs Applicability Determinations

82. The Permittee shall determine rule applicability and designation of affected sources under National Emission Standards for Hazardous Air Pollutants (NESHAPs) for Source Categories (40 C.F.R. 63) in accordance with the procedures described in 40 C.F.R. 63.1(b). If a source becomes affected by an applicable subpart of 40 C.F.R. 63, Permittee shall comply with such standard by the compliance date established by the Administrator in the applicable subpart.

82.1 The Permittee must keep a record of the applicability determination on site for a period of 5 years after the determination or until the source changes its operations to become an affected source, whichever comes first. The record of the applicability determination must be signed by the person making the determination and include an analysis (or other information) that demonstrates why the Permittee believes the source is unaffected. The analysis (or other information) must be sufficiently detailed to allow the Department to make a finding about the source's applicability status with regard to the relevant standard or other requirement.

[18 AAC 50.040(c)(1)(A) & (E) & 50.040(j), and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(3)(ii), and 40 C.F.R. 63.1(b) & 63.6(c)(1)]

7 Technology-based emission standard means a best available control technology standard (BACT); a lowest achievable emission rate standard (LAER); a maximum achievable control technology standard established under 40 C.F.R. 63, Subpart B, adopted by reference in 18 AAC 50.040(c); a standard adopted by reference in 18 AAC 50.040(a) or (c); and any other similar standard for which the stringency of the standard is based on determinations of what is technologically feasible, considering relevant factors.


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82.2 Permittee shall, within one year of the effective date of this permit, or within 180 days of the restart of EU ID 2, whichever is later, perform emission source testing and submit the final source test report under Section 8 for each of EU IDs 1 and 2 to test for emission concentrations and emission rates of hydrogen fluoride and hydrogen chloride according to the following guidelines:

a. Do not conduct test runs during periods of startup, shutdown, or malfunction;

b. At the beginning and at the end of each test run, extract an aliquot sample of the coal being burned before and after the test, and conduct the following on each aliquot coal sample:

(i) a proximate analysis using ASTM D5142-04;

(ii) an ultimate analysis using ASTM D5373-02;

(iii) analyses of the fluoride and chloride content of the coal using ASTM D4208 for Chlorine and D3761 for Fluoride; and

(iv) An analysis of the higher and lower heating value.

c. Attach the analysis results from item b above to the final source test report.

d. Conduct no less than three separate test runs for each test required. Each test run must last at least 1 hour.

e. Use EPA approved test methods to test hydrogen fluoride and hydrogen chloride as follows:

(i) Select sampling ports location and the number of traverse points according to Method 1;

(ii) Determine velocity and volumetric flow-rate of the stack gas according to Method 2, 2F, or 2G;

(iii)Determine oxygen and carbon dioxide concentrations of the stack gas according to Method 3A or 3B;

(iv) Measure the moisture content of the stack gas according to Method 4; and

(v) Measure the hydrogen chloride emission concentration according to Method 26 or 26A

f. Sampling sites must be located at the outlet of the emission control device and prior to any releases to the atmosphere.

g. For each emission unit test, convert the measured emission concentration to an emission rate according to 40 CFR 60 Appendix A Test Method 19 methodology. Calculate hydrogen fluoride and hydrogen chloride average emission concentrations and emission rates for each test run in each of the following units as follows:


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(i) in lbs/ MMBtu of heat input capacity of the tested emission unit;

(ii) in lbs/1000 lb steam; and

(iii) in lbs/hr

h. During each emission unit test, collect operating parameter data at least every 15 minutes during the entire emission unit test including:

(i) Steam production rates;

(ii) Air volume feed rates;

(iii) Relative contribution of air placement;

(iv) Process control oxygen analyzer at the control device;

(v) Pressure drop across the emission unit’s baghouse (if the emission unit is controlled by one at the time of the emission test);

(vi) Acid gas emissions control parameters including the reagent injection rates; and

(vii) Any other operating parameter data the Permittee wants to use to help determine its effect on HCl and HF emissions.

82.3 If the emission testing conducted under Condition 82.2 does not reflect normal plant operation after EU ID 2 start-up, conduct a second set of HCl and HF emission testing of that unit in accord with Condition 82.2 and Section 8 within 180 days after the Unit starts normal operations. The Department may waive this second set of test in writing for good cause.

82.4 Report in accordance with Section 8.

82.5 Report any changes of applicability status as set forth in Condition 82 based on the latest test results.

Halon Prohibitions, 40 C.F.R. 82

83. The Permittee shall not use halon at this facility. Compliance with this requirement shall consist of an annual certification according to Condition 101 that the Permittee is complying with this condition.

[18 AAC 50.040(d)] [40 C.F.R. 82.174 (b) - (d)]


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Open Burning Requirements

84. Open Burning. If the Permittee conducts open burning at this stationary source they shall comply with the requirements of 18 AAC 50.065.

84.1 The Permittee shall keep written records to demonstrate that the Permittee complies with the limitations in this condition and the requirements of 18 AAC 50.065. Upon request by the Department, submit copies of the records.

84.2 Compliance with this condition shall be an annual certification conducted under Condition 101.

[18 AAC 50.065, 18 AAC 50.040(j) and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(3)]


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Section 8. General Source Testing and Monitoring Requirements

85. Requested Source Tests. In addition to any source testing explicitly required by the permit, the Permittee shall conduct source testing as requested by the Department to determine compliance with applicable permit requirements.

[18 AAC 50.220(a) and 18 AAC 50.345(a) & (k)]

86. Operating Conditions. Unless otherwise specified by an applicable requirement or test method, the Permittee shall conduct source testing

[18 AAC 50.220(b)]

86.1 at a point or points that characterize the actual discharge into the ambient air; and

86.2 at the maximum rated burning or operating capacity of the emission unit or another rate determined by the Department to characterize the actual discharge into the ambient air.

87. Reference Test Methods. The Permittee shall use the following as reference test methods when conducting source testing for compliance with this permit:

87.1 Source testing for compliance with requirements adopted by reference in 18 AAC 50.040(a) must be conducted in accordance with the methods and procedures specified in 40 C.F.R. 60.

[18 AAC 50.220(c)(1)(A), and 18 AAC 50.040(a)] [40 C.F.R. 60]

87.2 Source testing for compliance with requirements adopted by reference in 18 AAC 50.040(b) must be conducted in accordance with the methods and procedures specified in 40 C.F.R. 61.

[18 AAC 50.040(b) and 18 AAC 50.220(c)(1)(B)] [40 C.F.R. 61]

87.3 Source testing for compliance with requirements adopted by reference in 18 AAC 50.040(c) must be conducted in accordance with the source test methods and procedures specified in 40 C.F.R. 63.

[18 AAC 50.040(c), and 18 AAC 50.220(c)(1)(C)] [40 C.F.R. 63]

87.4 Source testing for the reduction in visibility through the exhaust effluent must be conducted in accordance with the procedures set out in Reference Method 9 and may use the form in Section 13 to record data.

[18 AAC 50.030 and 18 AAC 50.220(c)(1)(D)]

87.5 Source testing for emissions of total particulate matter, sulfur compounds, nitrogen compounds, carbon monoxide, lead, volatile organic compounds, fluorides, sulfuric acid mist, municipal waste combustor organics, metals, and acid gases must be conducted in accordance with the methods and procedures specified in 40 C.F.R. 60, Appendix A.

[18 AAC 50.040(a)(3) and 18 AAC 50.220(c)(1)(E)] [40 C.F.R. 60, Appendix A]


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87.6 Source testing for emissions of PM-10 must be conducted in accordance with the procedures specified in 40 C.F.R. 51, Appendix M, Methods 201 or 201A and 202.

[18 AAC 50.035(b)(2) and 50.220(c)(1)(F)] [40 C.F.R. 51, Appendix M]

87.7 Source testing for emissions of any pollutant may be determined using an alternative method approved by the Department in accordance with 40 C.F.R. 63 Appendix A, Method 301.

[18 AAC 50.040(c)(24) and 50.220(c)(2)] [40 C.F.R. 63, Appendix A, Method 301]

88. Excess Air Requirements. To determine compliance with this permit, standard exhaust gas volumes must include only the volume of gases formed from the theoretical combustion of the fuel, plus the excess air volume normal for the specific emission unit type, corrected to standard conditions (dry gas at 68° F and an absolute pressure of 760 millimeters of mercury).

[18 AAC 50.220(c)(3) and 50.990(102)]

89. Test Exemption. The Permittee is not required to comply with Conditions 91, 92 and 93 when the exhaust is observed for visible emissions by Method 9 Plan (Condition 2.1) or Smoke/No Smoke Plan (Condition 2.2).

[18 AAC 50.345(a)]

90. Test Deadline Extension. The Permittee may request an extension to a source test deadline established by the Department. The Permittee may delay a source test beyond the original deadline only if the extension is approved in writing by the Department’s appropriate division director or designee.

[18 AAC 50.345(a) & (l)]

91. Test Plans. Except as provided in Condition 89, before conducting any source tests, the Permittee shall submit a plan to the Department. The plan must include the methods and procedures to be used for sampling, testing, and quality assurance and must specify how the emission unit will operate during the test and how the Permittee will document that operation. The Permittee shall submit a complete plan within 60 days after receiving a request under Condition 85 and at least 30 days before the scheduled date of any test unless the Department agrees in writing to some other time period. Retesting may be performed without resubmitting the plan.

[18 AAC 50.345(a) & (m)]

92. Test Notification. Except as provided in Condition 89, at least 10 days before conducting a source test, the Permittee shall give the Department written notice of the date and the time the source test will begin.

[18 AAC 50.345(a) & (n)]


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93. Test Reports. Except as provided in Condition 89, within 60 days after completing a source test, the Permittee shall submit two copies of the results in the format set out in the Source Test Report Outline, adopted by reference in 18 AAC 50.030. The Permittee shall additionally certify the results in the manner set out in Condition 96. If requested in writing by the Department, the Permittee must provide preliminary results in a shorter period of time specified by the Department.

[18 AAC 50.345(a) & (o)]

94. Particulate Matter Calculations. In source testing for compliance with the particulate matter standards in Conditions 5, 40, 59, and 64 the three-hour average is determined using the average of three one-hour test runs. The source testing must account for those emissions caused by soot blowing, grate cleaning, or other routine maintenance activities by ensuring that at least one test run includes the emissions caused by the routine maintenance activity and is conducted under conditions that lead to representative emissions from that activity. The emissions must be quantified using the following equation:

Equation 1

AR

SB

R

SRNM

EAR

SBA

MEE

Where:

E = the total PM emissions of the emission unit in grains per dry standard cubic foot (gr./dscf).

EM = the PM emissions in gr./dscf measured during the test that included the routine maintenance activity.

ENM = the arithmetic average of PM emissions in gr./dscf measured during the test runs that did not include the maintenance activity.

A = the period of routine maintenance activity occurring during the test run that included routine maintenance activity, expressed to the nearest hundredth of an hour.

B = the total period of the test run, less A.

R = the maximum period of emission unit operation per 24 hours, expressed to the nearest hundredth of an hour.

S = the maximum period of routine maintenance activity per 24 hours, expressed to the nearest hundredth of an hour.

[18 AAC 50.220(f)]


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Section 9. General Recordkeeping and Reporting Requirements

Recordkeeping Requirements

95. Recordkeeping Requirements. The Permittee shall keep all records required by this permit for at least five years after the date of collection, including:

[18 AAC 50.326(j)] [40 C.F.R 60.7(f), Subpart A and 71.6(a)(3)(ii)(B)]

95.1 copies of all reports and certifications submitted pursuant to this section of the permit; and

95.2 records of all monitoring required by this permit, and information about the monitoring including:

a. calibration and maintenance records, original strip chart or computer-based recordings for continuous monitoring instrumentation;

b. the date, place, and time of sampling or measurements;

c. the date(s) analyses were performed;

d. the company or entity that performed the analyses;

e. the analytical techniques or methods used;

f. the results of such analyses; and

g. the operating conditions as existing at the time of sampling or measurement.

Reporting Requirements

96. Certification. The Permittee shall certify any permit application, report, affirmation, or compliance certification submitted to the Department and required under the permit by including the signature of a responsible official for the permitted stationary source following the statement: “Based on information and belief formed after reasonable inquiry, I certify that the statements and information in and attached to this document are true, accurate, and complete.” Excess emission reports must be certified either upon submittal or with an operating report required for the same reporting period. All other reports and other documents must be certified upon submittal.

96.1 The Department may accept an electronic signature on an electronic application or other electronic record required by the Department if

a. a certifying authority registered under AS 09.25.510 verifies that the electronic signature is authentic; and

b. the person providing the electronic signature has made an agreement, with the certifying authority described in Condition 96.1a, that the person accepts or agrees to be bound by an electronic record executed or adopted with that signature.

[18 AAC 50.345(a) & (j), 18 AAC 50.205, and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(3)(iii)(A)]


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97. Submittals. Unless otherwise directed by the Department or this permit, the Permittee shall send two copies of reports, compliance certifications, and other submittals required by this permit to ADEC, Air Permits Program, 610 University Ave., Fairbanks, AK 99709-3643, ATTN: Compliance Technician. The Permittee may, upon consultation with the Compliance Technician regarding software compatibility, provide electronic copies of data reports, emission source test reports, or other records under a cover letter certified in accordance with Condition 96.

[18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(3)(iii)(A)]

98. Information Requests. The Permittee shall furnish to the Department, within a reasonable time, any information the Department requests in writing to determine whether cause exists to modify, revoke and reissue, or terminate the permit or to determine compliance with the permit. Upon request, the Permittee shall furnish to the Department copies of records required to be kept by the permit. The Department may require the Permittee to furnish copies of those records directly to the federal Administrator.

[18 AAC 50.345(a) & (i), 18 AAC 50.200, and 18 AAC 50.326(a) & (j)] [40 C.F.R. 71.5(a)(2) & 71.6(a)(3)]

99. Excess Emissions and Permit Deviation Reports. [18 AAC 50.235(a)(2), & 50.240(c), 18 AAC 50.326(j)(3), and 18 AAC 50.346(b)(2) & (3)]

99.1 Except as provided in Condition 78, the Permittee shall report all emissions or operations that exceed or deviate from the requirements of this permit as follows:

a. in accordance with 18 AAC 50.240(c), as soon as possible after the event commenced or is discovered, report

(i) emissions that present a potential threat to human health or safety; and

(ii) excess emissions that the Permittee believes to be unavoidable;

b. in accordance with 18 AAC 50.235(a), within two working days after the event commenced or was discovered, report an unavoidable emergency, malfunction, or non routine repair that causes emissions in excess of a technology based emission standard;

c. report all other excess emissions and permit deviations

(i) within 30 days of the end of the month in which the emissions or deviation occurs, except as provided in Conditions 99.1c(ii) and 99.1c(iii);

(ii) if a continuous or recurring excess emissions is not corrected within 48 hours of discovery, within 72 hours of discovery unless the Department provides written permission to report under Condition 99.1c(i); and

(iii) for failure to monitor, as required in other applicable conditions of this permit.


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99.2 When reporting excess emissions or permit deviations, the Permittee must report using either the Department’s on-line form, which can be found at http://www.dec.state.ak.us/air/ap/site.htm or https://myalaska.state.ak.us/dec/air/airtoolsweb/ , or if the Permittee prefers, the form contained in Section 15 of this permit. The Permittee must provide all information called for by the form that is used.

99.3 If requested by the Department, the Permittee shall provide a more detailed written report as requested to follow up an excess emissions report.

100. Operating Reports. During the life of this permit8, the Permittee shall submit to the Department an original and two copies of an operating report by August 1 for the period January 1 to June 30 of the current year and by February 1 for the period July 1 to December 31 of the previous year.

[18 AAC 50.346(b)(6), and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(3)(iii)(A)]

100.1 The operating report must include all information required to be in operating reports by other conditions of this permit.

100.2 If excess emissions or permit deviations that occurred during the reporting period are not reported under Condition 100.1, either

a. The Permittee shall identify

(i) the date of the deviation;

(ii) the equipment involved;

(iii) the permit condition affected;

(iv) a description of the excess emissions or permit deviation; and

(v) any corrective action or preventive measures taken and the date of such actions; or

b. When excess emissions or permit deviations have already been reported under Condition 99 the Permittee shall cite the date or dates of those reports.

100.3 The operating report must include a listing of emissions monitored under Conditions 2.1e, and 2.2c, 6.2, 8.1 and 11.2 (and for Condition 39.4, monitoring equipment failure) which trigger additional testing or monitoring, whether or not the emissions monitored exceed an emission standard. The Permittee shall include in the report

a. the date of the emissions;

b. the equipment involved;

c. the permit condition affected; and

d. the monitoring result which triggered the additional monitoring. 8 “Life of this permit” is defined as the permit effective dates, including any periods of reporting obligations that extend beyond the permit effective dates. For example if a permit expires prior to the end of a calendar year, there is still a reporting obligation to provide operating reports for the periods when the permit was in effect.


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100.4 Transition from expired to renewed permit. For the first period of this renewed operating permit, also provide the previous permit’s facility operating report elements covering that partial period immediately preceding the effective date of this renewed permit.

101. Annual Compliance Certification. Each year by March 31, the Permittee shall compile and submit to the Department one original9 and one copy of an annual compliance certification report.

101.1 Certify the compliance status of the stationary source over the preceding calendar year consistent with the monitoring required by this permit, as follows:

a. identify each term or condition set forth in Section 3 through Section 11, that is the basis of the certification;

b. briefly describe each method used to determine the compliance status;

c. state whether compliance is intermittent or continuous; and

d. identify each deviation and take it into account in the compliance certification.

101.2 Transition from expired to renewed permit. For the first period of this renewed operating permit, also provide the previous permit’s annual compliance certification report elements covering that partial period immediately preceding the effective date of this renewed permit.

101.3 In addition, submit a copy of the report directly to the EPA-Region 10, Office of Air Quality, M/S OAQ-107, 1200 Sixth Avenue, Seattle, WA 98101.

[18 AAC 50.205, 18 AAC 50.345(a) & (j), and 50.326(j)] [40 C.F.R. 71.6(c)(5)]

102. NSPS and NESHAP Reports. The Permittee shall:

102.1 attach to the facility operating report required by Condition 100, a copy of any NSPS and NESHAPs reports submitted to the U.S. Environmental Protection Agency (EPA) Region 10 as required by Conditions 55, 56, 58, 59 and 63; and

102.2 upon request by the Department, provide a written copy of any EPA-granted alternative monitoring requirement, custom monitoring schedule or waiver of the federal emission standards, record keeping, monitoring, performance testing, or reporting requirements.

[18 AAC 50.326(j)(4), and 18 AAC 50.040(j)] [40 C.F.R. 60.13, and 40 C.F.R. 71.6(c)(6)]

9 See Condition 101.2 for clarification on the number of reports required.


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Section 10. Permit Changes and Renewal

103. Permit Applications and Submittals: The Permittee shall comply with the following requirements for submitting application information to the US Environmental Protection Agency (EPA):

103.1 The Permittee shall provide a copy of each application for modification or renewal of this permit, including any compliance plan, or application addenda, at the time the application or addendum is submitted to the Department;

103.2 The information shall be submitted to the same address as in Condition 101.3;

103.3 To the extent practicable, the Permittee shall provide to EPA applications in portable document format (PDF); MS Word format (.doc); or other computer-readable format compatible with EPA's national database management system; and

103.4 The Permittee shall maintain records as necessary to demonstrate compliance with this condition.

[18 AAC 50.040(j)(7), 18 AAC 50.326(a), (b), & (j)(4)] [40 C.F.R. 71.10(d)(1))]

104. Emissions Trading: No permit revision shall be required under any approved economic incentives, marketable permits, emissions trading and other similar programs or processes for changes that are provided for in the permit.

[18 AAC 50.040(j)(4) and 18 AAC 50.326(j)] [40 C.F.R. 71.6(a)(8)]

105. Off Permit Changes. The Permittee may make changes that are not addressed or prohibited by this permit other than those subject to the requirements of 40 C.F.R. Part 72 through 78 or those that are modifications under any provision of Title I of the Act to be made without a permit revision, provided that the following requirements are met:


105.1 Each such change shall meet all applicable requirements and shall not violate any existing permit term or condition;

105.2 Provide contemporaneous written notice to EPA and the Department of each such change, except for changes that qualify as insignificant under 18 AAC 50.326(d) – (i). Such written notice shall describe each such change, including the date, any change in emissions, pollutants emitted, and any applicable requirement that would apply as a result of the change;

105.3 The change shall not qualify for the shield under 40 C.F.R. 71.6(f); and

105.4 The Permittee shall keep a record describing changes made at the stationary source that result in emissions of a regulated air pollutant subject to an applicable requirement, but not otherwise regulated under the permit, and the emissions resulting from those changes.


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106. Operational Flexibility. The Permittee may make section 502(b)(10) changes10 within the permitted stationary source without requiring a permit revision if the changes are not modifications under any provision of Title I of the Act and the changes do not exceed the emissions allowable under this permit (whether expressed therein as a rate of emissions or in terms of total emissions):

106.1 The Permittee shall provide EPA and the Department with a notification no less than 7 days in advance of the proposed change.

106.2 For each such change, the written notification required above shall include a brief description of the change within the permitted stationary source, the date on which the change will occur, any change in emissions, and any permit term or condition that is no longer applicable as a result of the change.

106.3 The permit shield described in 40 C.F.R. 71.6(f) shall not apply to any change made pursuant to Condition 106.


107. Permit Renewal. To renew this permit, the Permittee shall submit an application under 18 AAC 50.326 no sooner than August 3, 2015 and no later than August 3, 2016. The renewal application shall be complete before February 3, 2017. Permit expiration terminates the stationary source’s right to operate unless a timely and complete renewal application has been submitted consistent with 40 C.F.R. 71.7(b) and 71.5(a)(1)(iii).

[18 AAC 50.040(j)(3) and 18 AAC 50.326(a) and (j)(2)] [40 C.F.R. 71.5(a)(1)(iii), 71.6(c)(6), and 71.7(b) & (c)(1)(ii)]

108. Permit Applications. The Permittee shall send original applications for modification, or renewal of this permit and application addenda to the Department’s Anchorage office11. In addition, the Permittee may provide electronic copies of application documents; portable document format (PDF) or MS Word are acceptable formats.

[18 AAC 50.326(j)] [40 C.F.R. 71.7(a)(1)(i)]

109. The Permittee shall submit to the US Environmental Protection Agency (EPA) to the same address as in Condition 101.3:

109.1 a copy of any application for modification, or renewal of this permit and application addenda, at the time the application or addendum is submitted to the Department;

10 Section 502(b)(10) changes are changes that contravene an express permit term. Such changes do not include changes that would violate applicable requirements or contravene federally enforceable permit terms and conditions that are monitoring (including test methods), recordkeeping, reporting, or compliance certification requirements. [40 C.F.R. 71.2, 7/2/07] 11 The current address for the Anchorage office is: ADEC, 619 E. Ship Creek Ave., Ste 249, Anchorage, AK 99501


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109.2 to the extent practicable, the Permittee shall provide to EPA applications in computer-readable format compatible with EPA's national database management system. In the interim until EPA implements such system, portable document format (PDF) or MS Word are acceptable formats.

[18 AAC 50.040(j)(7) and 18 AAC 50.326(b)] [40 C.F.R. 70.10(d)(1)]


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Section 11. Compliance Requirements

General Compliance Requirements

110. Compliance with permit terms and conditions is considered to be compliance with those requirements that are

110.1 included and specifically identified in the permit; or

110.2 determined in writing in the permit to be inapplicable. [18 AAC 50.326(j)(3) and 18 AAC 50.345(a) & (b)]

111. The Permittee must comply with each permit term and condition.

111.1 For applicable requirements with which the Permittee is in compliance, the Permittee will continue to comply with such requirements.

111.2 Noncompliance with a permit term or condition constitutes a violation of AS 46.14.120(c), 18 AAC 50, and, except for those terms or conditions designated in the permit as not federally enforceable, the Clean Air Act, and is grounds for

a. an enforcement action;

b. permit termination, revocation and reissuance, or modification in accordance with AS 46.14.280; or

c. denial of an operating permit renewal application.

[18 AAC 50.326(j)(3) and 18 AAC 50.345(a) & (c)]

112. It is not a defense in an enforcement action to claim that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with a permit term or condition.

[18 AAC 50.326(j)(3) and 18 AAC 50.345(a) & (d)]

113. The Permittee shall allow the Department, or an inspector authorized by the Department, upon presentation of credentials and at reasonable times with the consent of the owner or operator to

113.1 enter upon the premises where a source subject to the permit is located or where records required by the permit are kept;

113.2 have access to and copy any records required by the permit;

113.3 inspect any stationary source, equipment, practices, or operations regulated by or referenced in the permit; and

113.4 sample or monitor substances or parameters to assure compliance with the permit or other applicable requirements.

[18 AAC 50.326(j)(3) and 18 AAC 50.345(a) & (h)] [18 AAC 50.040(j) & 18 AAC 50.326(j)]

[40 C.F.R. & 71.5(c)(8)(iii)(A)]


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114. For applicable requirements that will become effective during the permit term, the Permittee shall meet such requirements on a timely basis.

[18 AAC 50.040(j) & 50.326(j)] [40 C.F.R. 71.6(c)(3) & 71.5(c)(8)(iii)(B)]


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Section 12. Permit As Shield from Inapplicable Requirements In accordance with AS 46.14.290, and based on information supplied in the permit application, this section of the permit contains the requirements determined by the Department not to be applicable to the Healy Power Plant.

115. Nothing in this permit shall alter or affect the following:

115.1 The provisions of Section 303 of the Act (emergency orders), including the authority of the Administrator under that section; or

115.2 The liability of an owner or operator of a stationary source for any violation of applicable requirements prior to or at the time of permit issuance.

[18 AAC 50.326(j)] [40 C.F.R. 71.6(f)(3)(i)) and (ii)]

116. Table C identifies the emission units that are not subject to the specified requirements at the time of permit issuance. If any of the requirements listed in Table C becomes applicable during the permit term, the Permittee shall comply with such requirements on a timely basis including, but not limited to, providing appropriate notification to EPA, obtaining a construction permit and/or an operating permit revision.

[18 AAC 50.326(j)] [40 C.F.R. 71.6(f)(1)(ii)]


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Table C - Permit Shields Granted.

EU ID Non-Applicable Requirements Reason for non-applicability

3

40 C.F.R. Subpart Dc Installed in 1967 which is prior to June 9, 1989, the applicable date for Subpart Dc. This shield does not apply to future change to EU ID 3.

1

40 C.F.R. Subpart D

EU ID 1 construction was commenced in 1965 and commissioned to operate in September 1967, which is prior to August 17, 1971, the applicable date for Subpart D. This shield does not apply to future change to EU ID 1.

1 PSD BACT Emission Limits

EU ID 1 construction was commenced in 1965 and commissioned to operate in September 1967, which is prior to PSD requirements including BACT. This shield does not apply to future change to EU ID 1.

All

40 C.F.R. 82.158

The facility does not manufacture or import recycling and recovery equipment intended for use during the maintenance, service or repair of appliances.

All

40 C.F.R. 68

There is no process system that contains any compound at a quantity greater than the applicable threshold quantity as listed in 40 C.F.R. 68.

7 and 9 40 C.F.R. 60 Subpart OOO §60.674, §60.675(f), §60.676(c) – (e)

Facility does not use a wet scrubber to control emissions.

7 and 9 40 C.F.R. 60 Subpart OOO §60.676(a)

Facility is not seeking to comply with §60.670(d).

7 and 9 40 C.F.R. 60 Subpart OOO §60.672(g)

Facility does not operate multiple storage bins with combined stack emissions.

5 NSPS Subpart IIII The emission unit has not been modified or reconstructed since the Subpart applicability date.


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Section 13. Visible Emissions Forms

Visible Emissions Field Data Sheet

Certified Observer:

Company & Stationary

Source:

Location:

Test No.: Date:

Emission Unit:

Production Rate/Operating Rate:

Emission Unit Operating Hours:

Hrs. of observation:

Clock Time Initial Final

Observer location Distance to discharge

Direction from discharge

Height of observer point

Background description

Weather conditions Wind Direction

Wind speed

Ambient Temperature

Relative humidity

Sky conditions: (clear, overcast, % clouds, etc.)

Plume description: Color

Distance visible

Water droplet plume? (Attached or detached?)

Other information

Observers Position

Draw North Arrow


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Visible Emissions Observation Record

Page of

Company & Stationary Source Certified Observer

Test Number Clock Time

Date: Visibility reduction every 15

Seconds (Opacity) Steam Plume

(check if applicable) Comments

Hr Min 0 15 30 45 Attached Detached

Additional information:

Observer Signature and Date Certified By and Date

Data Reduction:

Duration of Observation Period (minutes): Duration Required by Permit (minutes) Number of Observations Highest Six –Minute Average Opacity (%) Number of Observations exceeding 20% In compliance with three-minute aggregate opacity limit? (Yes or No) In compliance with six-minute opacity limit? (Yes or No)

Average Opacity Summary Set Time Opacity

Number Start—End Sum Average


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Section 14. Material Balance Calculation If the sulfur content of a fuel shipment is greater than 0.75% by weight, calculate the three-hour exhaust concentration of SO2 using the following equations:

A. = 31,200 x [wt%Sfuel] = 31,200 x =

B. = 0.148 x [wt%Sfuel] = 0.148 x =

C. = 0.396 x [wt%Cfuel] = 0.396 x =

D. = 0.933 x [wt%Hfuel] = 0.933 x =

E. = B + C + D = + + =

F. = 21 – [vol%dryO2, exhaust] = 21 - =

G. = [vol%dryO2, exhaust] F = =

H. = 1 + G = 1 + =

I. = E x H = x =

SO2 concentration = A I = = ppm

The wt%Sfuel, wt%Cfuel, and wt%Hfuel are equal to the weight percents of sulfur, carbon, and hydrogen in the fuel. These percentages should total 100%. The fuel weight percent (wt%) of sulfur is obtained pursuant to Condition 14.1. The fuel weight percents of carbon and hydrogen are obtained from the fuel refiner. The volume percent of oxygen in the exhaust (vol%dryO2, exhaust) is obtained from oxygen meters, manufacturer’s data, or from the most recent ORSAT analysis at the same engine load used in the calculation. Enter all of the data in percentages without dividing the percentages by 100. For example, if wt%Sfuel = 1.0%, then enter 1.0 into the equations not 0.01 and if vol%dryO2, exhaust = 3.00%, then enter 3.00, not 0.03.

[18 AAC 50.346(c), 11/9/08]


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Section 15. ADEC Notification Form12 Stationary Source (Facility) Name Air Quality Permit Number

Company Name When did you discover the Excess Emissions/Permit Deviation?

Date: / / Time: : When did the event/deviation occur?

Begin Date: / / Time: : (please use 24hr clock)

End Date: / / Time: : (please use 24hr clock) What was the duration of the event/deviation?: : (hrs:min) or days(total # of hrs, min, or days, if intermittent then include only the duration of the actual emissions/deviation)

Reason for Notification: (please check only 1 box and go to the corresponding section)

Excess Emissions - Complete Section 1 and Certify.

Deviation from Permit Condition - Complete Section 2 and Certify

Deviations from COBC, CO, or Settlement Agreement - Complete Section 2 and Certify

Section 1. Excess Emissions

(a) Was the exceedance: or

(b) Cause of Event (Check one that applies):

Start Up /Shut Down

Natural Cause (weather/earthquake/flood)

Control Equipment Failure

Scheduled Maintenance/Equipment Adjustment

Bad fuel/coal/gas

Upset Condition Other

(c) Description

Describe briefly, what happened and the cause. Include the parameters/operating conditions exceeded, limits, monitoring data and exceedance. (d) Emissions Units Involved:

Identify the emission unit involved in the event, using the same identification number and name as in the permit. Identify each emission standard potentially exceeded during the event and the exceedance.

Unit ID Emission Unit Name Permit Condition Exceeded/Limit/Potential Exceedance

12 Revised as of August 20, 2008.

Intermittent Continuous


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(e) Type of Incident (Please Check only one).

Opacity % Venting (gas/scf) Control Equipment Down

Fugitive Emissions Emission Limit Exceeded Other:

Marine Vessel Opacity

Flaring

(f) Unavoidable Emissions:

Do you intend to assert that these excess emissions were unavoidable? Yes

No

Do you intend to assert the affirmative defense of 18 AAC 50.235? Yes

No

Certify Report (go to end of form)

Section 2 Permit Deviations (a) Permit Deviation Type (check one only box, corresponding with the section in the permit).

Source Specific Failure to monitor/report

General Source Test/Monitoring Requirements

Recordkeeping/Reporting/Compliance Certification Standard Conditions Not Included in Permit

Generally Applicable Requirements Reporting/Monitoring for Diesel Engines

Record Keeping Failure

Insignificant Source Facility Wide Other Section (title of section and section number of your permit).

(b) Emission Unit Involved.

Identify the emission unit involved in the event, using the same identification number and name

as in the permit. List the corresponding permit conditions and the deviation.

(c) Description of Potential Deviation: Describe briefly what happened and the cause. Include the parameters/operating conditions and the potential deviation.

Unit ID Emission Unit Name

Permit Condition / Potential Deviation


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(d) Corrective Actions: Describe actions taken to correct the deviation or potential deviation and to prevent future recurrence. Certification:

Based on information and belief formed after reasonable inquiry, I certify that the statements and information in and attached to this document are true, accurate, and complete.

Printed Name: Title: Date:

Signature: Phone Number:

NOTE: This document must be certified in accordance with 18 AAC 50.345(j)

To Submit this Report: 1. Fax to: 907-451-2187;

Or

2. Email to: [email protected] - if faxed or emailed,

Or

3. Mail to:

ADEC Air Permits Program 610 University Avenue Fairbanks, AK 99709-3643

Or

4. Phone Notification: 907-451-5173

Phone notifications require a written follow-up report.

Or

5. Submission of information contained in this report can be made electronically at the following website:

https://myalaska.state.ak.us/dec/air/airtoolsweb/

if submitted online, report must be submitted by an authorized E-Signer for the Stationary Source.

Statement of Basis February 3, 2012 Permit No.AQ0173TVP02

Page 1 of 38

Alaska Department of Environmental Conservation

Air Permits Program

Golden Valley Electric Association, Inc.

Healy Power Plant

STATEMENT OF BASIS

of the Terms and Conditions for

Permit No. AQ0173TVP02

Project Managed by:

Jim Plosay ADEC AQ/APP (Juneau)

Title V Program Requirements reviewed by:

Elizabeth Kerin ADEC AQ/APP (Fairbanks)

Prepared by Bill Walker, Blue Creek Consulting

February 3, 2012


Page 2 of 38

INTRODUCTION

This document sets forth the statement of basis for the terms and conditions of Operating Permit No. AQ0173TVP02.

STATIONARY SOURCE IDENTIFICATION

Section 1 of Operating Permit No.AQ0173TVP02 contains information on the stationary source as provided in the operating permit application.

The stationary source is owned by Golden Valley Electric Association, GVEA (owner of Unit No. 1 system), and Alaska Industrial Development and Export Authority, AIDEA (owner of HCCP system), and operated by Golden Valley Electric Association. Golden Valley Electric Association is the Permittee for the stationary source’s operating permit. The SIC code for this stationary source is 4911.

EMISSION UNIT INVENTORY AND DESCRIPTION

The Healy Power Plant is an electric power generating facility. The primary power generating units include two coal-fired steam generators, the 25-MW Foster-Wheeler Unit No. 1, installed in 1967, and the 54-MW Healy Clean Coal Project (HCCP) Integrated System, installed in 1996. There are also two Cleaver Brooks standby building heaters and one standby diesel generator. Unit No. 1 now also has a sorbent injection handling system for SO2 control. The related HCCP equipment consists of the crusher system, a limestone silo with baghouse and one vent to atmosphere, a fly ash silo with baghouse and two vents to atmosphere, a coal handling system, and two coal day bunkers with a common vent. Under 18 AAC 50.326(a), the Department requires operating permit applications to include identification of all emissions-related information, as described under 40 C.F.R. 71.5(c)(3).

The emission units at the Healy Power Plant that are classified and have specific monitoring, recordkeeping, and reporting requirements are listed in Table A of Operating Permit No. AQ0173TVP02.

Table A of Operating Permit No. AQ0173TVP02 contains information on the emission units regulated by this permit as provided in the application1. The table is provided for informational and identification purposes only. Specifically, the rating/size provided in the table is not intended to create an enforceable limit.

EMISSIONS

A summary of the potential to emit (PTE)2 and assessable PTE as calculated by the Department from the Healy Power Plant is shown in the table below.

1 The size and rating listed in Table A for EU ID 4 was the rated size approved by ADEC in the application for 173TVP01. The actual size differs; however, EU ID 4 has been mechanically limited to the approved rated size, 23.0 MMBtu/hr.

2 Potential to Emit or PTE means the maximum capacity of a stationary source to emit a pollutant under its physical or operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be treated as part of its design if the limitation or the effect it would


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Table D - Emissions Summary, in Tons Per Year (TPY)

Pollutant NOX CO PM-10 SO2 VOC HAPs CO2e Total

PTE 1,453 1,234 237 746 22 16 928,621 3,708

Assessable PTE 1,453 1,234 237 746 22 0 0 3,692

The assessable PTE listed under Condition 72.1 is the sum of the emissions of each individual regulated air pollutant for which the stationary source has the potential to emit quantities greater than 10 TPY. The emissions listed in Table D are estimates that are for informational use only. The listing of the emissions does not create an enforceable limit to the stationary source.

For criteria pollutants, emissions are as provided in the application, with minor changes.

The emission factors were largely from AP-42, and are limited by existing permit conditions, including BACT and ORL emissions limits from Condition 15, 16, 17, and 18. The Department corrected the selection of some AP-42 factors, with minimal changes in resulting emission rates.

For EU ID 1, CO and VOC emissions were based on an emission factor from CEMS data or from AP-42, the nominal heat input rate of 327 MMBtu/hr for the unit, and 8000 Btu/lb coal. The Department recalculated the emissions based on other information in the application showing that actual heat input rates were higher than 327 MMBtu/hr, and the average coal heat content in three years of data provided by GVEA. This increased the assessable potential to emit, but did not change permitting classifications or applicable requirements.

HAP emissions using available data indicate that Healy is HAP minor. But, as explained below, available data is insufficient for ADEC to concur. The permit contains additional HAP data collection requirements. HAP emissions are as provided in the application based on AP-42 emission factors, except for HCl and HF. The application based HCl emission calculations on the March 2004 EU ID 1 source test. The application based HF emission calculations on HCl emissions, and a ratio of HF to HCl from AP-42. The Department did not find that ratio to be applicable to Usibelli coal used at Healy. GVEA was able to provide the Department with

have on emissions is federally enforceable. Secondary emissions do not count in determining the potential to emit of a stationary source, as defined in AS 46.14.990(23), effective 12/3/05.


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additional information from the 2004 source test for HF emission rates. The Department used the EU ID 1 HF source test data as the starting point.

GVEA provided three years of monitoring data including sorbent (trona or sodium bicarbonate) injection rates for SO2 control. Sorbent is used in the amounts necessary to comply with an SO2 permit limit. Vendor information indicates that same sorbent is capable of a high degree of control of HCl and HF emissions. The sorbent injection data showed that injection rates were not always as high as the rate reported for the HCl and HF source test. During periods of decreased sorbent use, HF and HCl emission rates could be higher than recorded during the source test. HF emissions were calculated with best case and reasonable worst case assumptions:

Best case – HF emissions did not increase despite lower sorbent per power output rates. Calculated emissions – 1.9 ton per year HF.

Worst case – consistent with vendor literature, during the source test, control rate was 99%, no sorbent use implies 0% HF control, and control vs. sorbent use is linear between those end points. Calculated emissions – 9.5 tons per year.

No adjustment was made to adjust between actual and potential emissions because the sorbent injection rates could only be decreased very minimally to continue to comply with the SO2 limit. In the absence of any data, HCCP emissions were prorated from Emission Unit 1 based on nominal heat input ratings even though the lime calcining system acid gas control system for HCCP differs from Emission Unit 1’s trona injection system. The HCCP acid gas control system should control HCl and HF more efficiently than that of emission unit 1.

Chlorine coal content is less than the fluorine content. Chlorine emission factors were developed from HF emissions based on the 2004 source tests. Considering the difference between Emission Unit 1 and Unit 2 design and emission control systems, ADEC could neither refute nor agree with GVEA’s assumption.

Assuming coal fluorine content has remained constant, the actual HF emissions and potential to emit would be below 10 tons per year, and Healy would be HAP minor. However, Usibelli data indicates that coal fluorine content varies by almost an order of magnitude, and there is no data for that content during the 2004 source tests, or whether it has increased or decreased since. Due to the following reasons, ADEC could not conclude that the power plant is an area source nor could ADEC conclude that the plant is major for HAPs, a) worst case calculations are so close to the HAP major threshold; b) the emission units are not representative of one another; c) HF and HCl emission controls are a function of acid gas controls and the high variability of coal fluoride and chlorine content. Therefore, permit conditions require additional source testing along with coal fluorine and chlorine content analysis.

See also, the factual basis discussion for Condition 82 within this document.

After July 1, 2011, the GHG applicability threshold for an existing major stationary source threshold became 75,000 tons of CO2e for a modification, regardless if the project triggers major modification for another regulated NSR pollutant.

Because of this, the Department analyzed PSD permit applicability for greenhouse gases for this project. The Department calculated the nominal hourly coal consumption rate for the HCCP BAE at 41.1 tons per hour. GVEA projected the coal consumption rate for HCCP at 45.1 tons per hour. The change in annual coal consumption is 34,465 tons per year of sub-bituminous coal. Applying emission factors for CO2 for Usibelli Coal and pulverized coal methane and N2O


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for CO2 equivalence (CO2e), the Department calculated a net emissions increase of 53,278 tons of CO2e per year. Thus, the Department concluded that the increase would not approach the CO2e significance threshold for this regulated pollutant. Total CO2e calculations were provided by GVEA in a letter dated July 19, 2011.

BASIS FOR REQUIRING AN OPERATING PERMIT

In accordance with AS 46.14.130(b), an owner or operator of a Title V source3 must obtain an operating permit consistent with 40 C.F.R. Part 71, as adopted by reference in 18 AAC 50.040.

Except for sources exempted or deferred by AS 46.14.120(e) or (f), AS 46.14.130(b) lists three categories of sources that require an operating permit:

(1) A major source;

(2) A stationary source subject to federal new source performance standards or national emission standards;

(3) Another stationary source designated by the federal administrator by regulation.

This stationary source is a major stationary source further classified under 18 AAC 50.326(a) and 40 C.F.R. 71.3(a) as directly emitting, or having the potential to emit, 100 tpy or more of any air pollutant. This stationary source has the potential to emit more than 100 tpy each of CO, NOX, SO2 and PM-10.

AIR QUALITY PERMITS

Previous Air Quality Operating Permit

The most recent permit issued for this stationary source is Air Quality Operating Permit No. AQ0173TVP01, issued November 14, 2003, and most recently revised as Revision 2 November 10, 2004. Conditions of that permit are carried forward into this renewal as shown in Table E.

Previous Air Quality Permit to Operate

Permit-to-Operate No. 9431-AA001 included all construction authorizations issued through May 12, 1994. All source-specific requirements established in this previous permit were included in Operating Permit No. AQ0173TVP01, and are carried forward into this renewal, except as changed under the 1998 Construction Permit below. Title I (Construction and Minor) Permits

The Department issued Construction Permit No. 9831-AC018 to this stationary source on December 29, 1998. The source-specific requirements established in this construction permit were included in Operating Permit No. AQ0173TVP01, and are carried forward into this renewal. The Department issued no Title I (construction or minor) permits for this stationary source after the issuance of Operating Permit No. AQ0173TVP01.

3 “Title V source” means a stationary source classified as needing a permit under AS 14.130(b) [ref. 18 AAC 50.990(111)].


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On May 26, 2009, GVEA requested a PSD applicability determination from the Department regarding the startup of EU ID 2. On August 20, 2009, the Department issued their response letter (Subject: Permit Applicability Determination for resuming operation of the Healy Clean Coal Project) documenting its decision that bringing Emission Unit 2 out of warm layup would not trigger PSD review--Statement of Basis Appendix A. The Department’s underlying evaluation of this issue is contained in the October 12, 2009 Issue Statement (Title: Does a Prevention of Significant Deterioration Review Apply to the Restart of the HCCP?)--Statement of Basis Appendix B.

In response to additional issues raised through the public comment process, the Department supplemented the PSD applicability review by a) enhancing its basis for concluding that the project is not a modification; b) examining the commercial start-up project affiliated physical changes in their totality; and c) evaluating net emissions increase of the project to conclude that PSD does not apply. See Statement of Basis Appendix C.

Title V Operating Permit Application, Revisions and Renewal History

The owner or operator submitted the original operating permit application in November 1997. Operating Permit No. AQ0173TVP01 became effective December 14, 2003. On August 5, 2004, GVEA submitted a request to revise Operating Permit No. AQ0173TVP01, Revision 1. GVEA requested Permit Revision 2. The following changes were effective in Revision 2 on November 10, 2004

Table 1 –Inventory was updated to correctly describe which components are included in each system.

Table 2 - BACT and Owner Requested Emission Limits corrects the 365 ton per year carbon monoxide emission limit. The 365 ton per year was just an emission estimate; it was carried forward from Permit to Operate No. 9431-AA001 for all other emission units except EU IDs 2 and 4.

Table 3 - Permit Shields Granted was updated to include EU ID 9 as not subject to 40 CFR 60, Subpart OOO sections 60.674, 60.675(f), 60.676(c)-(e), 60.676(a) and 60.672(g).

Requirements to measure and record steam production for EU IDs 1 and 2 were removed because there are no steam production limits for these emission units.

Conditions 22.1(d) and (f) were combined into one condition under Condition 22.1(f) to correct a typographical error that referenced the wrong condition.

The owner or operator submitted a renewal application on June 16, 2008 (application dated June 12, 2008).

The owner or operator amended this application on September 2, 2008 (dated August 28, 2008).

Additional information was received April 2, 2009, April 17, 2009 and August 25, 2009.


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COMPLIANCE HISTORY

The stationary source has operated at its current location since 1967. Review of the permit files for this stationary source, which includes the past inspection reports and compliance evaluations, indicate a stationary source generally operating in compliance with its operating permit. CO emissions from Unit 1 increased beyond PSD thresholds of the Alaska Air Quality Control Program after installing low NOx burners and over-fire air as required under the 1993 Memorandum of Agreement with the National Park Service, Department of Energy and Alaska Industrial Development and Export Authority and GVEA. On June 27, 2002,GVEA summarized an informal agreement by which GVEA would minimize CO emissions without sacrificing the unit’s low NOx emissions and continue to optimize the reduction of CO with the existing configuration.

During the 90 day test phase, HCCP had 35 hours of SO2 violations, and 14 hours of high opacity readings. None of these occurred during normal operation. Opacity violations occurred when the unit was using fuel oil and the baghouse was off line, apparently all during startup. Actions taken included reducing the time the baghouse was off line. SO2 violations occurred during startup, shutdown, or change out of the Spray Dryer Absorber (SDA) atomizer. All were conditions when the SDA was off line. The permit does not contain a compliance plan because HCCP was in compliance when it discontinued operation.

APPLICABLE REQUIREMENTS FROM PRE-CONSTRUCTION PERMITS

Incorporated by reference at 18 AAC 50.326(j), 40 C.F.R. Part 71.6 defines “applicable requirement” to include the terms and conditions of any pre-construction permit issued under rules approved in Alaska’s State Implementation plan.

Alaska’s State Implementation Plan included the following types of pre-construction permits:

Permit-to-Operate issued before January 18, 1997 (these permits cover both construction and operations);

Construction Permits issued after January 17, 1997; and

Minor Permits issued after October 1, 2004.

Pre-construction permit terms and conditions include both source-specific conditions and conditions derived from regulatory applicable requirements such as standard conditions, generally applicable conditions and conditions that quote or paraphrase requirements in regulation.

All pre-construction permit terms and conditions that apply to the Healy Power Plant were included in Operating Permit No. AQ0173TVP01. Table E lists the condition numbers and subject matter of each condition of Operating Permit No. AQ0173TVP01, and any changes made to that condition in this revision.


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Table E - Comparison of Previous Operating Permit No. AQ0173TVP01, Revision 2 Conditions to Operating Permit No. AQ0173TVP02 Conditions4

Permit No. AQ0173TVP01,

Revision 2 Condition number

Description of Requirement


Condition Number How Condition was revised

Introductory Condition

Authority for Permit

None Moved to Statement of Basis

Table 1 Source list Table A - Emission Units Inventory

Same information

1 & 2 Emission Fees 72 & 73 New assessable PTE 3 Visible Emission

Standard 1 20% three minute aggregate

standard deleted – no longer part of the SIP

4 PM Standard 5 Same information 5 SO2 Standard 14 Same information

Condition 6 and Table 2

BACT and Owner Requested Emission Limits

Condition 15 and Table B

Same information

6 through 15 BACT and Owner Requested Emission Limits

16 through 24 NOX limit for HCCP changed from 0.350 lb/MMBtu to 0.325 lb/MMBtu at request of Permittee. Annual emissions adjusted accordingly.

16 SO2 and NOX reduction after completion of demonstration test phase

25 Same information


26 through 30 Same information

4 This table does not include all standard and general conditions.


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22 BACT and Owner Requested Emission Limits: Emission monitoring for coal fired boilers, Emission Units 1 and 2

31 Underlying state opacity standard changed. Deleted obsolete monitoring which no longer had an underlying requirement and replaced it with monitoring suitable for the current standard. Condition did not include monitoring for comparison to annual SO2 concentration limit. Add such wording. Added analysis for fluorine and chlorine to ultimate coal analysis – necessary for HAP major/minor determination.



29 BACT and Owner Requested Emission Limits: Source test for HCl, HF

82 Requires an HF and HCl additional source test for both units, along with sorbent injection rates and coal fluorine and chlorine content.

30 NSPS Subpart A Startup, shutdown, malfunction

43 Same information

31 NSPS Subpart A EEMSP report

44 Consistent with 40 C.F.R. 60.7(c), removed reporting requirement for emission limits without CEMS. Condition 31 requires reports quarterly. Condition rewritten using the NSPS language requiring the report for each period (60.7(c)(4)), but providing for reduced frequency when the limit is not exceeded.


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32 NSPS Subpart A EEMSP Summary report

45 This condition only applies if a CEMS is required. Emission units not needing CEMS removed from condition.

33 through 36 NSPS Subpart A: Good AP Control Practice, Credible Evidence, Concealment of Emissions, and Monitoring

46 through 49 Same information, except one cross reference corrected.

37 through 42 NSPS Subpart Da 50 through 55 Same information, except: Added the percent reduction standard for NOX

Added Da PM and NOX provisions that compliance with emission limit constitutes compliance with percent reduction requirements Added 60.48Da(h) regarding minimum data collection Updated to new C.F.R. citations Added the requirements of 40 C.F.R. 60.51Da(c), (d), (f), (h) to (k) Deleted the statement that the SO2 standard does not apply during startup and shutdown because 40 C.F.R. 60.48Da(c) does not contain that provision


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43 through 46 NSPS Subpart Dc 56 through 59 Edits to more closely reflect 60.48c(g)

Added NSPS requirements that fuel supplier certification include the sulfur content of the oil, and that Permittee calculate 30 day average sulfur content

Added the statement that the opacity standard applies at all times, except during periods of startup, shutdown, or malfunction

Deleted references to CEMS and COMS that do not apply

Added condition that opacity monitoring use the same condition as for the state opacity standard

Added reporting deadlines consistent with Subpart Dc

47 through 50 NSPS Subpart OOO


51 NSPS Subpart Y 64 Same information


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52 through 54 Visible emissions monitoring, records, reports

2 through 4 Allows continuing a plan from the previous permit. For replacement units, observe exhaust within 30 days of startup Add sun location to M9 data recorded Add 18-minute averaging requirement for emission units 6-10 as criteria for Method 5 testing – makes condition consistent with pm monitoring conditions.

55 through 57 PM MR&R for Diesel engines

6 and 7 Condition 56 measurement of stack diameter was a one-time requirement not included in the renewal.

58 and 59 PM MR&R for liquid fired boilers and heaters

8 through 10 PM monitoring, record keeping, and reporting changed to be consistent with the current Standard Permit Condition IX

60 through 62 PM MR&R for baghouses



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63 Coal fired boiler visible emissions

39 Corrected visible emission standard for Emission Unit 2. For Emission Unit 1, deleted reference to requirements that have already been met. Added cross references to requirements for COMS. Added recording and notification consistent with Standard Condition XIII. Added: keep calculated one minute averages and audit records. Added: notification of COMS malfunction. Replaced condition 63.4 with provisions appropriate to the changes in the 20% opacity standards – for emission unit 1 the six minute aggregate allowed during soot blowing, etc, and for emission unit 2 the change to a six minute average. Corrected reporting to conform to underlying NSPS to include any six minute average greater than 27%


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64 CFB particulate matter

40 For submitting test plans changed “before 80 percent of the allowable operating hours before the next test have elapsed” to “60 days before” -consistent with current standard condition; Include chlorine and fluorine content in operating report; added provisions for CAM

65 and 66 Sulfur Compound Emissions and monitoring

41 The frequency of coal sampling for sulfur content was changed to match the Title I condition from permit 9431-AA001.

67 Performance Audits for COMS

42 Same information

68 NESHAP applicability determination

82 Changes compliance date with new NESHAP to date established in the subpart (consistent w/ 63.6(c)(1))

69 through 72 Insignificant Emission Units

38 Conditions changed to reflect current Standard Condition V

73 Asbestos NESHAP

80 Same information

74 Refrigerant Recycling

81 Same information

75 through 78 Good AP Control Practice; Dilution; Reasonable Precautions (fugitive dust); Stack Injection


79 Open burning 84 Same information 80 Air Pollution

Prohibited 78 Same information

81 Technology based emission standard

79 Same information


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82 Permit renewal 107 Added statements that renewal application shall be complete before expiration date, and that permit expiration terminates the right to operate unless a timely and complete application have been submitted.

83 through 92 General Source Testing and Monitoring Requirements

85 through 94 Same information, except added coal fired boiler particulate matter standards (not including NSPS) to Condition 94 for Particulate Matter Calculations

93 through 96 Certification; Submittals; Information Requests; Recordkeeping Requirements


97 Excess Emissions and Permit Deviation Reports

99 Updated citations of reporting form locations and other updates to standard condition.

98 NSPS and NESHAP Reports

102 Same information

99 Operating Reports 100 Added provisions for electronic submittal and other updates to standard condition.

100 Annual Compliance Certification

101 Notarization no longer required; added provision for certification during transition from expired permit to renewal

101 through 107 Standard Conditions Not Otherwise Included in the Permit


108 and Table 3 Permit as Shield 115, 116, and Table C

Added caveats of 40 C.F.R. 71.6(f)(3)(i)) and (ii)


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NON-APPLICABLE REQUIREMENTS

Each permit is required to contain a discussion of all applicable requirements as set forth in 40 C.F.R. 71.6(a) adopted in 18 AAC 50.040(j). This section discusses standard conditions that have been removed from the permit or are not included for specific reasons.

NSPS Subpart IIII: Although the Permittee has one CI ICE (EU ID 5), it has not been modified or reconstructed since the Subpart applicability date and is not an affected facility. A permit shield has been granted for this regulation.


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STATEMENT OF BASIS FOR THE PERMIT CONDITIONS

The state and federal regulations for each condition are cited in Operating Permit No. AQ0173TVP02. The Statement of Basis provides the legal and factual basis for each term and condition as set forth in 40 C.F.R. 71.6(a)(1)(i).

Conditions 1 and 2 - 4, Visible Emissions Standard and MR&R

Legal Basis: These conditions ensure compliance with the applicable requirements in 18 AAC 50.055(a).

18 AAC 50.055(a) applies to the operation of fuel-burning equipment and industrial processes. EU IDs 3 – 6, 9, and 10 are fuel-burning equipment or industrial processes. (EU IDs 1 and 2 are also fuel burning equipment but are addressed separately in Section 4 of the permit.)

U.S. EPA incorporated these standards as revised in 2002 into the State Implementation Plan (SIP) effective September 13, 2007. Note: By doing so, EPA removed from the SIP the previous three minute aggregate standard of 50.055(a).

Factual Basis: Condition 1 prohibits the Permittee from causing or allowing visible emissions in excess of 18 AAC 50.055(a)(1).

The Permittee must monitor, record-keep and report emissions in accordance with Conditions 2 through 4, of the permit for each of EU IDs 3 – 10. While EU IDs 7 and 8 are not fuel burning equipment or industrial processes subject to a visible emissions standard, they are subject to particulate matter standards from the 1994 Title I permit. Visible emission monitoring is used in this permit as a screening tool for determining if Method 5 particulate matter testing is warranted.

Conditions 2 - 4 - MR&R conditions are standard conditions adopted into regulation pursuant to AS 46.14.010(e).

The Department has previously determined that the standard conditions adequately meet the requirements of 40 C.F.R. 71.6(a)(3). No emission unit or stationary source operational or compliance factors indicate the unit-specific or stationary-source-specific conditions would better meet the requirements. Therefore, the Department concludes that the standard conditions meet the requirements of 40 C.F.R. 71.6(a)(3).

Liquid Fired Fuel Burning Equipment:

Monitoring – The visible emissions may be observed by either Method-9 or the Smoke/No Smoke plans as detailed in Condition 2. Corrective actions such as maintenance procedures and either more frequent or less frequent testing may be required depending on the results of the observations.

Recordkeeping – The Permittee is required to record the results of all visible emission observations and record any actions taken to reduce visible emissions.

Reporting – The Permittee is required to report: 1) emissions in excess of the federal and the state visible emissions standard and 2) deviations from permit conditions. The Permittee is required to include copies of the results of all visible emission observations with the stationary source operating report.


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Insignificant Sources:

For EU IDs 3 through 5 no visible emissions monitoring is required because these are insignificant emission units based on actual emissions. As long as each unit does not operate more than 400 hours per year, it is an insignificant emission unit as specified in 18 AAC 50.326(e) and no monitoring is required in accordance with Department Guidance AWQ 02-014. The Permittee must annually certify compliance under Condition 101 with the opacity standard. If operation of any of these emission units exceeds 400 hours, the Permittee must use that standard reporting requirement of Conditions 2 - 4.

Because the 400 hour monitoring trigger is not an enforceable limit otherwise requiring monitoring, recordkeeping, or reporting, the Department has added a requirement to report if any of the emission units exceeds 400 hours and requires standard monitoring. Similarly, the Department has added a requirement to report if any of the emission units exceeds 800 hours and requires a second observation under Condition 2.1g.

Conditions 5 and 6 - 7, 8 - 10, & 11 - 13, Particulate Matter (PM) Standard

Legal Basis: These conditions ensure compliance with the applicable requirement in 18 AAC 50.055(b). This requirement applies to operation of all industrial processes and fuel burning equipment in Alaska.

EU IDs 3 - 5 are fuel-burning equipment. (EU IDs 1 and 2 are also fuel-burning equipment, but are addressed separately in Section 4.)

EU IDs 6, 9, and 10 are industrial processes.

These PM standards also apply because they are contained in the federally approved SIP effective September 13, 2007.

Condition 5 also lists the more stringent standards listed in Table A for EU IDs 6 and 10 from a 1994 Title I permit.

Factual Basis: Condition 5 prohibits emissions in excess of the state PM (also called grain loading) standard applicable to fuel-burning equipment and industrial processes, and the more stringent grain loading standard that applies to EU IDs 6 and 10 through the 1994 Title I permit. The Permittee shall not cause or allow fuel-burning equipment nor industrial processes to violate these standards.

MR&R requirements are listed in Conditions 6 - 7 for EU ID 5 (Diesel engine), Conditions 8 - 10 for EU IDs 3 and 4 (liquid fired heaters and boilers), and Conditions 11 - 13 for EU IDs 6 – 10 (baghouses).

The Permittee must establish by actual visual observations which can be supplemented by other means, such as a defined Operation and Maintenance Program, that the emission unit is in continuous compliance with the State's emission standards for particulate matter.

Liquid Fired

For liquid fuel units the MR&R conditions are Standard Condition IX adopted into regulation pursuant to AS 46.14.010(d). The Department determined that these standard conditions adequately meet the requirements of 40 C.F.R. 71.6(a)(3). No emission unit or stationary source operational or compliance factors indicate that unit-specific or stationary-source


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specific conditions would better meet these requirements. Therefore, the Department concluded that the standard conditions meet the requirements of 40 C.F.R. 71.6(a)(3).

Baghouses

MR&R for baghouses rely on visible emission monitoring to determine if particulate matter monitoring is warranted. If visible emissions exceed thresholds (although not necessarily exceeding visible emission standards) the Permittee has the opportunity to perform maintenance to reduce the emissions before scheduling particulate matter testing. The Department finds that these standard conditions adequately meet the requirements of 40 C.F.R. 71.6(a)(3).

Insignificant Sources:

For EU IDs 3 through 5 no monitoring is required because these are insignificant emission units based on actual emissions. As long as each unit does not operate more than 400 hours per year, it is an insignificant emission unit as specified in 18 AAC 50.326(e) and no monitoring is required in accordance with Department Guidance AWQ 02- 014. The Permittee must annually certify compliance under Condition 101 with the particulate matter standard.

Condition 14, Sulfur Compound Emissions

Legal Basis: This condition requires the Permittee to comply with the sulfur compound emission standard for all fuel-burning equipment and industrial processes in the State of Alaska.

EU ID(s) 3 – 5 are fuel-burning equipment.

These sulfur compound standards also apply because they are contained in the federally approved SIP effective September 13, 2007.

Factual Basis: The condition requires the Permittee to comply with the sulfur compound emission standard applicable to fuel-burning equipment. The Permittee may not cause or allow the affected equipment to violate this standard.

Sulfur dioxide comes from the sulfur in the fuel (e.g. coal, natural gas, fuel oils).

Liquid Fuels: For oil fired fuel burning equipment the MR&R conditions are Standard Conditions XI and XII adopted into regulation pursuant to AS 46.14.010(d). The Department determined that these standard conditions adequately meet the requirements of 40 C.F.R. 71.6(a)(3). No emission unit or stationary source operational or compliance factors indicate that unit-specific or stationary-source specific conditions would better meet these requirements. Therefore, the Department concluded that the standard conditions meet the requirements of 40 C.F.R. 71.6(a)(3).

Conditions 15 - 37, Pre-Construction Permit Requirements

Legal Basis: The Permittee is required to comply with all effective stationary source-specific requirements that were carried forward from previous EPA PSD permits, SIP approved permits to operate issued before January 18, 1997, SIP approved construction permit(s), SIP approved minor permits, operating permits issued between January 18, 1997 and September 30, 2004 or owner requested limits established under 18 AAC 50.225. These


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requirements include Best Available Control Technology limits, limits to ensure compliance with the attainment or maintenance of ambient air quality standards or maximum allowable ambient concentrations, and owner requested limits. State pre-construction requirements apply because they were originally developed through case-by-case action under a federally approved SIP or approved Operating Permit program. EPA approved the latest SIP effective September 13, 2007.

Factual Basis: Conditions 15 - 37 were established in Air Quality Control Permit to Operate No. 9431-AA001, 5/12/94 and Construction Permit No. 9831-AC018, 12/29/98. The stationary source-specific permits from these two permits were incorporated into Operating Permit No. AQ0173TVP01, and are carried forward into this renewal permit.

The Department determined that the continuous monitoring of oxides of nitrogen, carbon monoxide, and sulfur compounds developed in Permit 9431-AA001 and as modified by Permit 9831-AC01 meet the obligations of 40 CFR 71.6 for periodic monitoring. However, for compliance with the BACT and owner requested limits for EU IDs 1 and 2 under Condition 15 as well as the State Air Quality Control emission standard and Federal New Source Performance Standards stated elsewhere, the Department added to Condition 40 more frequent periodic particulate matter emission source testing obligations for the coal fired boilers because the boiler emissions are highly variable and the emissions are actually controlled through use of a baghouse on each coal fired-unit.

To amend Conditions 15 through 37, the Permittee must request a Title I permit under 18 AAC 50.508(5).

Condition 25: Part 25 and 25.1of this condition were carried forward from Permit-to-Operate No. 9431-AA001 (PSD permit). Healy Unit 2 was designed to operate using an experimental technology for control of NOX and SO2; emissions estimates from this technology were not part of the BACT database at the time the 1994 operating permit was issued. The NOX and SO2 emissions limits that were achievable using the best available control technology at the time of issuance of the 1994 permit were used as Emission Unit 2 emission limits in the 1994 permit to operate. The experimental technology used in Emission Unit 2 has the potential capability to reduce NOX and SO2 emissions below the 1994 BACT limits. Condition 25 and 25.1 were designed to provide a process to re-evaluate the NOX and SO2 emission limits for Emission Unit 2 if this reduction in emissions does indeed occur.

Condition 38, Insignificant Emission Units

Legal Basis: The Permittee is required to meet state emission standards set out in 18 AAC 50.055 for all industrial processes and fuel-burning equipment, regardless of size.

Factual Basis: The condition reiterates the emission standards and requires compliance for insignificant emission units. The Permittee may not cause or allow their equipment to violate these standards. Insignificant emission units are not listed in the permit unless specific monitoring, recordkeeping and reporting are necessary to ensure compliance.

The Department finds that the insignificant units at this stationary source do not require specific monitoring, recordkeeping and reporting to ensure compliance under these conditions.


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Condition 38.4 requires certification based on reasonable inquiry that the emission units did not exceed state emission standards during the previous year and did not emit any prohibited air pollution.

Conditions 39 -41 (Section 4), Conditions for Coal-Fired Boilers, Including Standard Operating Conditions for Boilers in Operation before July 1972

This section includes the requirements of Standard Condition XIII for Emission Unit 1 and for Emission Unit 2, which is not subject to the standard condition, other appropriate standards, monitoring, record keeping and reporting. Section 4 also includes Compliance Assurance Monitoring.

Legal Basis: The Permittee is required to comply with coal-fired fuel burning equipment standards set out in 18 AAC 50.055 for visible emissions, particulate matter and sulfur compounds. EPA approved these standards as part of the state implementation plan effective September 13, 2007.

Factual Basis: Opacity For the coal-fired fuel unit that began operation before August 17, 1971 (EU ID 1), these conditions include 18 AAC 50.055(a)(9)(A) and (B) for allowing emissions exceeding 20% opacity for up to three minutes in an hour, and during startup, shutdown, soot-blowing, grate cleaning or other routine maintenance activities specified in the permit, six minutes in an hour. [Permit conditions do not include 18 AAC 50.055(a)(9)(C) and (D) because those have been satisfied for EU ID 1.] EU ID 2, which was built after 1971, is subject to 18 AAC 50.055(a)(1), which has changed to a six minute average not to exceed 20% opacity. For EU ID 1, conditions in Section 4 also include Standard Condition XIII adopted into 18 AAC 50.346(c) Table 7 pursuant to AS 46.14.010(d). The Department determined that these standard conditions adequately meet the requirements of 40 C.F.R. 71.6(a)(3) as long as the COMS is in service. The permit adds provisions in Condition 39.4 for opacity monitoring when the COMS is out of service.

Standard Condition XIII only applies to EU ID 1. EU ID 2 (HCCP) was constructed in 1996, so the standard condition and the visible emission standard of 18 AAC 50.055(a)(9) do not apply. The Department has added comparable conditions, including a requirement for a COMS for EU ID 2 to satisfy 40 C.F.R. 71.6(a)(3), and 40 C.F.R. 60 Subpart Da.

The Emission Unit 1 and 2 reporting condition for state opacity standard from Permit-to-Operate No. 9431-AA001was not included because its underlying requirements (not more than 20% for more than three minutes in any one hour) no longer apply, as mentioned above. Correct reporting requirements have been added in Condition 39.5 to replace the provisions that no longer apply.

In addition to the state visible emission standard in 18 AAC 50.055(a)(1), EU ID 2 is subject to the NSPS opacity limit in 40 C.F.R. 60, Subpart Da. That standard is the same as 18 AAC 50.055(a)(1), except that it allows one six minute period per hour to exceed 20%, but not exceed 27%. (Any 6-minute average over 20% would still be a violation of the state standard.)


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Particulate Matter

A particulate matter standard of 0.05 gr/dscf applies to both Emission Units 1 and 2. 18 AAC 50. 055(b)(1) applies to Emission unit 2. Emission unit 1 is subject to the 0.1 gr/dscf standard of 18 AAC 50.055(b)(2), but is also subject to 0.05 gr/dscf from Permit-to-Operate No. 9431-AA001.

Standard conditions related to steam production limits are not included. No such limits apply to EU IDs 1 or 2. In addition for EU IDs 1 and 2, the Department added Condition 40 imposing periodic particulate matter emission source testing obligations for the coal fired boilers within a year of startup, and once every 8760 hours of operation thereafter. The Compliance Assurance Monitoring (CAM) of 40 C.F.R. 64 applies to Emission units 1 and 2 for particulate matter. Each emission unit has potential emissions before controls exceeding 100 tons per year, and requires the use of a control device to comply with particulate matter applicable requirements. While each emission unit is required to have a COMS, the emission units are not exempted under 40 C.F.R. 64.1 and 64.2 because the COMS do not meet the definition of continuous compliance determination method for particulate matter. They do not provide data in the units or averaging period of the particulate matter limits, and the Permittee has not correlated opacity directly with those limits. The applicant has also not proposed presumptively acceptable monitoring described in 40 C.F.R. 64.4(b). Condition 40.6 also contains the CAM monitoring which applies to particulate matter emission limits that do not have continuous monitoring associated with the underlying limit. For Healy these include state emission standards, limits carried over from the PSD permit, and, for EU ID 2, the applicable limit of 40 C.F.R. 60, Subpart Da. The applicant initially proposed the use of baghouse pressure drop proposed by the applicant in the CAM plan. In ex parte communication with the Department, the applicant submitted a draft CAM plan that proposes the use of particulate matter source testing to determine a baseline opacity, with additional monitoring and correction to be taken if opacity remains above this baseline for a set amount of time. This additional monitoring is modeled after 40 C.F.R. 60.48Da(o), although neither EU ID 1 or 2 are subject to 40 C.F.R 60.48Da(o). Since the Department has not approved the GVEA CAM plan, Condition 40.6 allows 180 days from issuance of AQ0173TVP02 for the Permittee to submit a revised CAM plan. Condition 40.6 includes gap-filling requirements applicable until a revised CAM plan is accepted by the Department. Under the permit, GVEA is further allowed to submit a new or revised CAM plan (that could include continuous particulate matter monitoring). This revised plan should be submitted in the form of an application for a permit modification. The Department shall determine in writing that the revised plan meets the requirements of 40 C.F.R. 64 before it will be substituted for the current permit condition. The new plan does not need to follow 40 CFR 60.48Da(o) in order to be approved.


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Sulfur Compound Emissions

The 500 ppm SO2 standard of 18 AAC 50.055(c) applies to EU IDs 1 and 2. Monitoring conditions Standard Condition XIII would apply to emission unit 1. However, Title I monitoring conditions already apply from Permit to Operate No. 9431-AA001. Therefore monitoring conditions require SO2 CEMs , and monthly fuel sampling, instead of the standard language.

Condition 42 (Section 5), Performance Audits for COMS

Legal Basis: The Permittee is required to follow the Department’s performance audits for Continuous Opacity Monitoring Systems (COMS) revised as of January 26, 2004. EPA approved this provision as part of the Alaska State Implementation Plan effective September 13, 2007 but did not incorporate it by reference under 40 C.F.R. 52 Subpart C.

Factual Basis: This stationary source contains coal-fired boilers required to install a COMS under Conditions 19 and 20. The conditions cross-references the obligation to perform COMS audits periodically during the life of the permit in accord with 18 AAC 50.030(9).

Conditions 43– 49, NSPS Subpart A Requirements

Legal Basis The Permittee must comply with those New Source Performance Standard (NSPS) provisions incorporated by reference from the NSPS effective July 1, 2007, for specific industrial activities, as listed in 18 AAC 50.0405.

At this stationary source, EU IDs 2, 4, 6, 7, 9 and 10 are affected facilities subject to NSPS Subparts Da, Dc, Y, and OOO, and therefore are subject to Subpart A.

The Permittee has already complied with the notification requirements in 40 C.F.R. 60.7 (a)(1) - (4) for EU IDs 2, 4, 6, 7, 9 and 10. However, the Permittee would still be subject to these requirements in the event of a new NSPS affected facility or in the event of a modification or reconstruction of an existing facility into an affected facility.

Condition 43 - The requirements to notify the EPA and the Department of any proposed replacement of an existing facility (40 C.F.R. 60.15) apply to EU ID(s) 1, 3, and 5 in the event of a proposed replacement of these existing facilities.

Condition 43 - Start-up, shutdown, or malfunction record maintenance requirements in 40 C.F.R. 60.7(b) are applicable to all NSPS affected facilities subject to Subpart A.

Conditions 44 and 45 - NSPS excess emission reporting requirements and summary report form in 40 C.F.R. 60.7(c) & (d) are applicable to EU ID 2 because it is subject to NSPS continuous monitoring system requirements. The Department has included in Attachment A of the statement of basis a copy of the federal EEMSP summary report form for use by the Permittee.

Recordkeeping requirements in 40 C.F.R. 60.7(f) are applicable to all NSPS affected facilities. (Satisfied by Condition 95)

5 EPA has not delegated to the Department the authority to administer the NSPS program as of the issue date of this permit.


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Condition 46 - Good air pollution control practices in 40 C.F.R. 60.11 are applicable to all NSPS affected facilities subject to Subpart A (EU IDs 2, 4, 6, 9 and 10.

Condition 47 - States that any credible evidence may be used to demonstrate compliance or establishing violations of relevant NSPS standards for EU IDs 2, 4, 6, 9 and 10. This implements 40 C.F.R. 60.11(g).

Condition 48 - Concealment of emissions prohibitions in 40 C.F. R. 60.12 are applicable to EU IDs 2, 4, 6, 9, and 10.

Condition 49 - Monitoring requirements in 40 C. F. R. 60.13 are applicable to EU ID 2 because a CMS is used to determine compliance with Subpart Da emission standards.

Factual Basis: Subpart A contains the general requirements applicable to all affected facilities (sources) subject to NSPS. In general, the intent of NSPS is to provide technology-based emission control standards for new, modified and reconstructed affected facilities.

Conditions 50 - 55, NSPS Subpart Da Requirements

Legal Basis: NSPS Subpart Da applies to electric utility steam generating units for which construction is commenced after September 18, 1978 and have maximum design heat input capacities of more than 73 MW. EU ID 2 was constructed in 1996, and has a maximum design heat input capacity of 658 MMBtu/hr; and is therefore subject to Subpart Da. Factual Basis: These conditions require the Permittee to comply with Subpart Da particulate matter, sulfur, and nitrogen oxides standards. The Permittee may not cause or allow EU ID 2 to violate these standards. Note that several other limits, determined as BACT or requested as ORLs, are more stringent than the Subpart Da standards for these pollutants. The state emission standard testing requirements have been cross referenced with this subpart for PM standard gap filling.

Conditions 56 - 59, NSPS Subpart Dc Requirements

Legal Basis: Since the Permittee identified an affected facility at this stationary source, these conditions require the Permittee to comply with NSPS Subpart Dc. The NSPS applies to steam generating units for which construction, modification, or reconstruction commenced after June 9, 1989 and have maximum design heat input capacities of 29 MW (100 MMBtu/hr) or less, but greater than or equal to 2.9 MW (10 MMBtu/hr). EU ID 4 was constructed in 1996. The current application shows that it has a maximum design heat input capacity of 23 MMBtu/hr; it is therefore subject to Subpart Dc.

EU ID 4, when burning distillate fuel oil, is subject to the standard for SO2 in 40 C.F.R. 60.42c(d). In accordance with 40 C.F.R. 60.42c(h)(1) and 40 C.F.R. 60.46c(e), compliance with the emission limit or oil sulfur content limit for EU ID 4 may be demonstrated by certification from the fuel supplier.

The PM standard in 40 C.F.R. 60.43c applies to an affected facility with a design heat input greater than or equal to 30 MMBtu/hr. Because the application for the original Operating permit stated that the design heat input is 32 MMBtu/hr, this permit includes the PM standard as an applicable requirement. As a practical matter, this will not change the stringency of


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applicable requirements, as the state emission standard in 18 AAC 50.055(a)(1) is in the same format and is more stringent.

Factual Basis: The conditions require the Permittee to comply with the Subpart Dc sulfur standard. The Permittee may not cause or allow EU ID 4 to violate this standard. The Permittee has two options for complying with SO2 emissions: one is to comply with a sulfur emission limit and the other is to comply with a fuel sulfur limit.

The PM standard imposes an opacity limit.

Monitoring - The condition describes monitoring required in the event that the owner seeks to demonstrate compliance with the SO2 standard based on fuel supplier certification under 40 C.F.R. 60.44c(h) and 60.46c(e).

40 C.F.R. 60.47c(c) and (f) rely on a site specific monitoring plan for opacity, rather than a COMS if the affected facility burns only distillate fuel oil. The permit therefore uses the monitoring plan established in standard conditions for the applicable state opacity standard.

Conditions 60 through 63, NSPS Subpart OOO Requirements

Legal Basis: EU ID 7 has a baghouse that controls emissions from only an individual, enclosed storage bin. Stack emissions are limited to 7 percent opacity as stated in §60.672(f). EU ID 9 includes a mill, silo and baghouse. Particulate matter and opacity are limited by §60.672(a). §60.672(e) applies to any fugitive or mechanically induced emissions from a building containing any transfer point or other affected facility, as described in §60.670. Factual Basis: The Permittee shall comply with the reporting requirements in §60.676(f) and §60.675(c)(2).

Condition 64, NSPS Subpart Y Requirements

Legal Basis: NSPS Subpart Y applies to affected facilities in coal preparation plants which process more than 181 Mg (200 tons) per day. EU IDs 6 and 10 are classified as facilities in a coal preparation plant and can process more than 200 tons of coal per day; therefore EU IDs 6 and 10 are subject to Subpart Y. Factual Basis: The condition requires the Permittee to comply with Subpart Y visible emission standards. The Permittee may not cause or allow EU IDs 6 and 10 to violate these standards.

Condition 65, NESHAPs Subpart A

Legal Basis: The Department has incorporated by reference the NESHAP requirements effective July 16, 2007, for specific industrial activities, as listed in 18 AAC 50.040(c).

Most sources subject to a NESHAPs requirement are subject to Subpart A. EU ID 5 is subject to NESHAPs Subpart ZZZZ and is therefore subject to the provisions of Subpart A listed in Table 8 of Subpart ZZZZ.

Factual Basis: These conditions incorporate applicable 40 C.F.R. 63 requirements. The Permittee may not cause or allow violations of these prohibitions.


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Condition 66 NESHAPs Subpart ZZZZ

Legal Basis: NESHAPS Subpart ZZZZ applies to stationary compression ignition reciprocating internal combustion engines (CI RICE) at major and area sources of hazardous air pollutants. EU IDs 5 and 11 are subject to Subpart ZZZZ under 40 C.F.R. 60.6580 because they are emergency stationary CI RICE which commenced construction or reconstruction before June 12, 2006, and are located at an area source of HAPs emissions.

Factual Basis: EU ID 11 was insignificant until it became subject to NESHAP Subpart ZZZZ. This condition incorporates the Subpart ZZZZ operations and emissions standards applicable to EU ID 5 and 11. The Permittee may not cause or allow EU IDs 5 or 11 to violate these standards. This condition also provide MR&R specifically called for within the Subpart. The Permittee is required to monitor and maintain records related to notification; start up; shut down; and malfunction and repair. Reporting of excess emissions and hours of operation is required.

Condition 67 NESHAPs Subpart JJJJJJ

Legal Basis: NESHAPS Subpart JJJJJJ applies to industrial boilers at area sources of hazardous air pollutants that are not otherwise regulated under Part 63. EU IDs 3 and 4 are subject to Subpart JJJJJJ under 40 C.F.R. 63.11193 and 63.11194 because they are existing oil fired industrial boilers. The boilers are not rated at 25 MW, and do not provide electric utility power, and are located at an area source of HAPs emissions.

Factual Basis: Because EU IDs 3 and 4 are oil fired boilers with a heat input greater than 10 MMBtu/hr, they are not subject to NESHAPs emission standards or operating limits, but are required to have biennial tune-ups.

Reporting consists of submitting the Notice of Compliance Status for initial compliance, and submitting the Department’s copy of the biennial certification with the operating permit compliance certification of Condition 101.

The Department does not have sufficient information to make a determination of HAPS major status as the information currently available is inconclusive. The permit contains testing and notification terms and conditions to make this determination. If the Permittee finds under Condition 82 that the Healy Power Plant is HAP major, Subpart JJJJJJ would not apply, but the Permittee would have to comply with Subpart DDDDD instead as set forth in Condition 70.

The EU IDs 1 and 2 are not subject to Subpart JJJJJJ because they are electric generating utility boilers that will be subject to 40 C.F.R. 63, Subpart UUUUU when U.S. EPA promulgates the final rule. The July 30, 2007 U.S. Court of Appeals for the U.S. District Court remanded the utility boiler MACT standard. The court requires EPA to complete the final rulemaking by November 16, 2011.


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Conditions 68 - 70, Standard Terms and Conditions

Legal Basis: These are standard conditions required under 18 AAC 50.345(a) and (e)-(g) for all operating permits. This provision is incorporated in the federally approved Alaska operating permit program of November 30, 2001, as updated effective November 9, 2008.

Factual Basis: These are standard conditions that apply to all permits.

Condition 71, Administration Fees

Legal Basis: This condition ensures compliance with the applicable requirement in 18 AAC 50.400-405 as derived from AS 46.14.130. This condition requires the Permittee, owner, or operator to pay administration fees as set out in regulation. Paying administration fees is required as part of obtaining and holding a permit with the Department or as a fee for a Department action.

Factual Basis: The owner or operator of a stationary source who is required to apply for a permit under AS 46.14.130 shall pay to the Department all assessed permit administration fees. The regulations in 18 AAC 50.400-405 specify the amount, payment period, and the frequency of fees applicable to a permit action.

Conditions 72 - 73, Emission Fees

Legal Basis: These conditions ensure compliance with the applicable requirement in 18 AAC 50.410-420. The regulations require all permits to include due dates for the payment of fees and any method the Permittee may use to re-compute assessable emissions.

Factual Basis: These emission fee conditions are standard condition I under 18 AAC 50.346(b) adopted pursuant to AS 46.14.010(d). The Department determined that these standard conditions adequately meet the requirements of AS 46.14.250. No emission unit or stationary source operational or compliance factors indicate that unit-specific or stationary-source specific conditions would better meet these requirements. Therefore, the Department concluded that the standard conditions meet the requirements of AS 46.14.250.

These standard conditions require the Permittee to pay fees in accordance with the Department's billing regulations. The billing regulations set the due dates for payment of fees based on the billing date.

The default assessable emissions are generally potential emissions of each air pollutant in excess of 10 tons per year authorized by the permit (AS 46.14.250(h)(1)(A)). The Department recalculated the potential emissions presented in the application to use correct AP-42 emission factors and to replace two assumptions for emission unit 1. (Application assumed 8000 btu/lb coal and 327 MMBtu/hr. Elsewhere the application indicated operation above the 327 MMBtu/hr nominal rating assuming the coal heat content of 8000 btu/lb. Subsequently GVEA corrected the application with supplemental coal values of 7000 btu/lb coal. Data that was provided as supplemental information to the application showed that the average heat content of the coal for Emission unit 1 over three years was a little less than 7000 btu/lb coal.)

The conditions allow the Permittee to calculate actual annual assessable emissions based on previous actual annual emissions. According to AS 46.14.250(h)(1)(B), assessable emissions are based on each air pollutant. Therefore, fees based on actual emissions shall be paid on any pollutant emitted whether or not the permit contains any limitation of that pollutant.


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This standard condition specifies that, unless otherwise approved by the Department, calculate assessable emission based on actual emissions using the most recent previous calendar year's emissions. Since each current year's assessable emission are based on the previous year operations, the Department will not adjust the billings at the end of the current year if the estimated assessable emissions and current year actual emissions do not match.

The Department modified the standard condition to correct Condition 73.2 such that it referenced “submitted” (i.e., postmarked) rather than “received” in accordance with the timeframe of Condition 73.1.

Condition 74, Good Air Pollution Control Practice

Legal Basis: This condition ensures compliance with the applicable requirement in 18 AAC 50.346(b)(5) and applies to all emission units, except those subject to federal emission standards, those subject to continuous emission or parametric monitoring, and for insignificant emission units, i.e., except EU IDs 2, 4, 5, 6, 7, 9 and 10.

Factual Basis: The condition requires the Permittee to comply with good air pollution control practices for all units. EU ID 5 is subject to this condition only until it is replaced with Condition 66.1 on the applicable compliance date as set forth in Condition 66.

The Department adopted this condition under 18 AAC 50.346(b) as Standard Operating Permit Condition VI pursuant to AS 46.14.010(d). This condition has been modified in the permit because EU ID 5 is subject to a federal standard (NESHAPS SUBPART ZZZZ) with an applicable compliance date that occurs during the time period of this permit. The Department added the text “ EU ID 5 is subject to this condition only until it is replaced with Condition 66.1 on the applicable compliance date as set forth in Condition 66.”

Maintaining and operating equipment in good working order is fundamental to preventing unnecessary or excess emissions. Standard conditions for monitoring compliance with emission standards are based on the assumption that good maintenance is performed. Without appropriate maintenance, equipment can deteriorate more quickly than with appropriate maintenance. If appropriate maintenance is not applied to the equipment, the Department may have to apply more frequent periodic monitoring requirements (unless the monitoring is already continuous) to ensure that the monitoring results are representative of actual emissions.

The Permittee is required to keep maintenance records to show that proper maintenance procedures were followed, and to make the records available to the Department. The Department may use these records as a trigger for requesting source testing if the records show that maintenance has been deferred.

Condition 75, Dilution

Legal Basis: This condition prohibits the Permittee from using dilution as an emission control strategy as set out in 18 AAC 50.045(a). This state regulation applies to the Permittee because the Permittee is subject to emission standards in 18 AAC 50.

Factual Basis: The condition prohibits the Permittee from diluting emissions as a means of compliance with any standard in 18 AAC 50.

Condition 76, Reasonable Precautions to Prevent Fugitive Dust


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Legal Basis: This condition requires the Permittee to use reasonable precautions when handling, storing or transporting bulk materials or engaging in an industrial activity in accordance with the applicable requirement in 18 AAC 50.045(d). Bulk material handling requirements apply to the Permittee because the Permittee will engage in bulk material handling, transporting, or storing; or will engage in industrial activity at the stationary source.

The standard condition for monitoring compliance with this requirement (Standard Condition X) is not included in the permit because the stationary source has an approved dust control plan.

Factual Basis: The condition requires the Permittee to comply with 18 AAC 50.045(d), and take reasonable action to prevent particulate matter (PM) from being emitted into the ambient air.

Condition 77, Stack Injection

Legal Basis: This condition ensures compliance with the applicable requirement in 18 AAC 50.045(e)-(f). It prohibits the Permittee from releasing materials other than process emissions, products of combustion, or materials introduced to control pollutant emissions from a stack (i.e. disposing of material by injecting it into a stack). Stack injection requirements apply to the stationary source because the stationary source contains a stack or emission unit constructed or modified after November 1, 1982.

Factual Basis: No specific monitoring for this condition is practical. Compliance is ensured by inspections, because the emission unit or stack would need to be modified to accommodate stack injection.

Condition 78, Air Pollution Prohibited

Legal Basis: This condition ensures compliance with the applicable requirement in 18 AAC 50.110. The condition prohibits the Permittee from causing any emission which is injurious to human health or welfare, animal or plant life, or property, or which would unreasonably interfere with the enjoyment of life or property. Air Pollution Prohibited requirements apply to the stationary source because the stationary source will have emissions.

Factual Basis: While the other permit conditions and emissions limitation should ensure compliance with this condition, unforeseen emission impacts can cause violations of this standard. These violations would go undetected except for complaints from affected persons. Therefore, to monitor compliance, the Permittee must monitor and respond to complaints.

ADEC adopted this standard condition into 18 AAC 50.346(a) pursuant to AS 46.14.010(d). The Department determined that this condition adequately meet the requirements of 40 C.F.R. 71.6(a)(3). No emission unit or stationary source operational or compliance factors indicate that unit-specific or stationary-source specific conditions would better meet these requirements. Therefore, the Department concluded that the standard condition meets the requirements of 40 C.F.R. 71.6(a)(3).

The Permittee is required to report any complaints and injurious emissions. The Permittee must keep records of the date, time and nature of all complaints received, summary of the


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investigation and corrective actions undertaken for these complaints and to submit copies of these records upon request of the Department.

Condition 79, Technology-Based Emission Standard

Legal Basis: The Permittee is required to take reasonable steps to minimize emissions if certain activity causes an exceedance of any technology-based emission standard in this permit. This condition ensures compliance with the applicable requirement in 18 AAC 50.235. Technology Based Emission Standard requirements apply to the stationary source because the stationary source contains equipment subject to a technology-based emission standard, such as BACT, MACT, LAER, NSPS or other “technologically feasible” determinations.

Factual Basis: The conditions of this permit list applicable technology-based emission standards and require excess emission reporting for each standard in accordance with Condition 99. Excess emission reporting under Condition 99 requires information on the steps taken to minimize emissions. Monitoring of compliance for this condition consists of the report required under Condition 99.

Condition 80, Asbestos NESHAP

Legal Basis: The condition requires the Permittee to comply with asbestos demolition or renovation requirements in 40 C.F.R. 61, Subpart M. This condition ensures compliance with the applicable requirement in 18 AAC 50.040(b)(1) and (2)(F). The asbestos demolition and renovation requirements apply if the Permittee engages in asbestos demolition or renovation.

Factual Basis: Because these regulations include adequate monitoring and reporting requirements and because the Permittee is not currently engaged in such activity, simply citing the regulatory requirements is sufficient to ensure compliance with these federal regulations.

Condition 81, Refrigerant Recycling and Disposal

Legal Basis: This condition ensures compliance with the applicable requirement in 18 AAC 50.040(d) and applies if the Permittee engages in the recycling or disposal of certain refrigerants. The condition requires the Permittee to comply with the standards for recycling and emission reduction of refrigerants set forth in 40 C.F.R. 82, Subpart F, that will apply if the Permittee uses certain refrigerants.

Factual Basis: Because these regulations include adequate monitoring and reporting requirements and because the Permittee is not currently engaged in such activity, simply citing the regulatory requirements is sufficient to ensure compliance with this federal regulation.

Condition 82, NESHAPS Applicability Determinations

Legal Basis: This condition requires the Permittee to keep and make available to the Department copies of the major stationary source determination and applicability of specific federal regulations that may apply to its stationary sources.


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Factual Basis: The Permittee has conducted an analysis of the stationary source and determined that it is not a major HAPs stationary source based on emissions. However, additional monitoring required in this permit will require re-evaluation of HAP status. This condition requires the Permittee to keep and make available to the Department copies of the major stationary source determination.

Condition 82 - Hydrogen chloride is a hazardous air pollutant and, if its emission level equals or exceeds 10 TPY, the plant is defined as a HAP major source and is therefore subject to applicable MACT (40 C.F.R. 63) standards. The AP-42 emission factor for coal boilers indicate that a coal fired power plants of this size would emit greater than10 TPY of HCl. However, upon issuance of AQ0173TVP01 GVEA suspected that the Healy coal does not have chloride levels as high as the coals used to generate the AP-42 emission factor. Also, since the Healy coals have a low sulfur concentration, their ash would tend to be more alkaline. The more alkaline ash would tend to capture more of the HCl and convert it to metal chlorides. Common metal chlorides are not HAPs. However, fluoride content of the Usibelli coal source is great enough that if uncontrolled and all is converted to HF, the power plant would be HF HAPS major. Condition 29 of Operating Permit No. AQ0173TVP01 required GVEA to conduct a one-time source test for Units 1 and 2 for HCl. Unit 2 has not yet operated under this permit. GVEA also measured HF during the test. HF was emitted in greater quantity than HCl. The stationary source’s annual potential to emit HCl and HF would be below 10 tons for each pollutant if the rates measured during the source test are assumed to represent worst case representative HF and HCl emissions. However, the emission rates depend upon the rate of sorbent injection used to control SO2 and precursor properties of the coal burned. Using sorbent injection data for EU ID 1 and reasonable worst case assumptions, HF emissions would be slightly less than 10 tpy assuming both units have similar rates of HF and HCL control efficiency, as long as the fluorine content of the coal and control efficiency remain constant. However, information from Usibelli, the coal supplier, shows that fluorine content varies by almost an order of magnitude. Neither the fluorine content during the source test, nor the average content for any year since has been reported to ADEC. As a result it presently is not possible to determine if coal with a high fluorine content would result in emissions greater than 10 tpy. Condition 82.2 of this permit requires the Permittee to conduct an HCl and HF source test on each boiler and to collect fluorine and chlorine data for the coal burned during the test. The Permittee shall use the results of this test to determine the HCl and HF PTE and the HAP status of the stationary source. Condition 31 requires coal fluorine and chlorine content be measured and reported quarterly after the source test.

Condition 83, Halon Prohibitions

Legal Basis: These prohibitions apply to all stationary sources that use halon for extinguishing fires and inert gas to reduce explosion risk. The condition prohibits the Permittee from causing or allowing violations of these prohibitions.


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Factual Basis: This condition incorporates applicable 40 C.F.R. 82 requirements. The Permittee may not cause or allow violations of these prohibitions.

Condition 84, Open Burning

Legal Basis: The condition requires the Permittee to comply with the regulatory requirements when conducting open burning at the stationary source. This condition ensures compliance with the applicable requirement in 18 AAC 50.065. The open burning state regulation in 18 AAC 50.065 applies to the Permittee if the Permittee conducts open burning at the stationary source.

Factual Basis: No specific monitoring is required for this condition. Condition 84 requires the Permittee to keep records to demonstrate compliance with the standards for conducting open burning, but does not specify what these records should contain.

More extensive monitoring and recordkeeping is not warranted because the Permittee does not conduct open burning as a routine part of their business. Also, most of the requirements are prohibitions, which are not easily monitored. Additional monitoring is achieved through Condition 78, which requires a record of complaints.

Condition 85, Requested Source Tests

Legal Basis: The Permittee is required to conduct source tests as requested by the Department. The Department adopted this condition under 18 AAC 50.345(k) as part of its operating permit program approved by EPA November 30, 2001.

Factual Basis: This condition ensures compliance with the applicable requirement in 18 AAC 50.220(a) and applies because this is a standard condition to be included in all operating permits. Monitoring consists of conducting the requested source test.

Conditions 86 - 88, Operating Conditions, Reference Test Methods, Excess Air Requirements

Legal Basis: These conditions ensure compliance with the applicable requirement in 18 AAC 50.220(b) and apply because the Permittee is required to conduct source tests by this permit. The Permittee is required to conduct source tests as set out in Conditions 86 through 88.

Factual Basis: These conditions supplement the specific monitoring requirements stated elsewhere in this permit. Compliance monitoring with Conditions 86 through 88 consist of the test reports required by Condition 93.

Condition 89, Test Exemption

Legal Basis: This condition ensures compliance with the applicable requirement in 18 AAC 50.345(a) and applies when the emission unit exhaust is observed for visible emissions.

Factual Basis: As provided in 18 AAC 50.345(a), amended November 9, 2008, the requirements for test plans, notifications and reports do not apply to visible emissions observations by smoke readers, except in connection with required particulate matter testing.

Conditions 90 - 93, Test Deadline Extension, Test Plans, Notifications and Reports


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Legal Basis: These conditions ensures compliance with the applicable requirement in 18 AAC 50.345(l)-(o) and apply because the Permittee is required to conduct source tests by this permit.

Factual Basis: Standard conditions 18 AAC 50.345(l) - (o) are incorporated through these conditions. These standard conditions supplement specific monitoring requirements stated elsewhere in this permit. The source test itself monitors compliance with this condition.

Condition 94, Particulate Matter (PM) Calculations

Legal Basis: This condition requires the Permittee to reduce particulate matter data in accord with 18 AAC 50.220(f). It applies when the Permittee tests for compliance with the PM standards in 18 AAC 50.050 or 50.055.

Factual Basis: The condition incorporates a regulatory requirement for PM source tests. The Permittee must use the equation given in this condition to calculate the PM emission concentration from the source test results. This condition supplements specific monitoring requirements stated elsewhere in this permit.

Condition 95, Recordkeeping Requirements

Legal Basis: Applies because the Permittee is required by the permit to keep records.

Factual Basis: The condition restates the regulatory requirements for recordkeeping, and supplements the recordkeeping defined for specific conditions in the permit. The records being kept provide an evidence of compliance with this requirement.

Condition 96, Certification

Legal Basis: This condition requires the Permittee to comply with the certification requirement in 18 AAC 50.205 and applies to all Permittees under EPA’s approved operating permit program of November 30, 2001.

Factual Basis: This standard condition is required in all operating permits under 18 AAC 50.345(j).

This condition requires the Permittee to certify any permit application, report, affirmation, or compliance certification submitted to the Department. To ease the certification burden on the Permittee, the condition allows the excess emission reports to be certified with the stationary source report, even though they must still be submitted more frequently than the stationary source operating report. This condition supplements the reporting requirements of this permit.

Condition 97, Submittals

Legal Basis: This condition requires the Permittee to comply with standardized reporting requirement in 18 AAC 50.326(j) and applies because the Permittee is required to send reports to the Department.

Factual Basis: This condition lists the Department’s appropriate address for reports and written notices. Receipt of the submittal at the correct Department office is sufficient


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monitoring for this condition. This condition supplements the standard reporting and notification requirements of this permit.

Condition 98, Information Requests

Legal Basis: This condition requires the Permittee to submit requested information to the Department. This is a standard condition from 18 AAC 50.345(i) of the state approved operating permit program effective November 30, 2001.

Factual Basis: This condition requires the Permittee to submit information requested by the Department. Monitoring consists of receipt of the requested information.

Condition 99, Excess Emission and Permit Deviation Reports

Legal Basis: This condition requires the Permittee to comply with the applicable requirement in 18 AAC 50.235(a)(2) and 18 AAC 50.240. Also, the Permittee is required to notify the Department when emissions or operations deviate from the requirements of the permit.

Factual Basis: This condition satisfies two state regulations related to excess emissions - the technology-based emission standard regulation and the excess emission regulation. Although there are some differences between the regulations, the condition satisfies the requirements of each regulation.

The Department adopted this condition as Standard Operating Permit Condition III under 18 AAC 50.346(c) pursuant to AS 46.14.010(d). The Department determined that this standard condition adequately meet the requirements of 40 CFR 71.6(a)(3). No emission unit or stationary source operational or compliance factors indicate that unit-specific or stationary-source specific conditions would better meet these requirements. Therefore, the Department concluded that the standard conditions meet the requirements of 40 CFR 71.6(a)(3). The Department made a correction to the Standard Operating Permit Condition III to allow identical reporting methodology for both Excess Emissions and Permit Deviations reports which use identical forms and should have identical submissions methods.

Section 15, Notification Form

The Department also uses the form as set out in Standard Condition IV as revised August 20, 2008.

Condition 100, Operating Reports

Legal Basis: This condition ensures compliance with the applicable requirement in 18 AAC 50.346(b)(6) and applies to all permits.

Factual Basis: The condition is Standard Condition VII and restates the requirements for reports listed in regulation. The condition supplements the specific reporting requirements elsewhere in the permit. The reports themselves provide monitoring for compliance with this condition.

Condition 101, Annual Compliance Certification

Legal Basis: This condition ensures compliance with the applicable requirement in 18 AAC 50.040(j)(4) and applies to all Permittees.


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Factual Basis: This condition specifies the periodic compliance certification requirements, and specifies a due date for the annual compliance certification. Each annual certification provides monitoring records for compliance with this condition.

Condition 101.2 provides clarification of transition periods between an expiring permit and a renewal permit to ensure that the Permittee certifies compliance with the permit terms and conditions of the permit that was in effect during those partial date periods involved in the transition. No format is specified. The Permittee may provide one report certifying compliance with each permit term or condition and the effective permit at that time, or may chose to provide two reports – one certifying compliance with permit terms and conditions from January 1 until the date of expiration of the old permit, and a second report certifying compliance with terms and conditions in effect from the effective date of the renewal permit until December 31.

The Permittee may submit one of the required copies electronically at their discretion. This change more adequately meets the requirements of 18 AAC 50 and agency needs, as the Department can more efficiently distribute the electronic copy to staff in other locations.

Condition 102, NSPS and NESHAP Reports

Legal Basis: The Permittee is required to provide the federal Administrator and Department a copy of each emission unit report for units subject to NSPS or NESHAP federal regulations under 18 AAC 50.326(j)(4). 40 C.F.R. 70 Appendix A documents that EPA fully approved the Alaska operating permit program effective November 30, 2001.

Factual Basis: The condition supplements the specific reporting requirements in 40 C.F.R. 60, 40 C.F.R. 61, and 40 C.F.R. 63. The reports themselves provide monitoring for compliance with this condition.

Condition 103, Permit Applications and Submittals

Legal Basis: The Permittee may need to submit permit applications and related correspondence.

Factual Basis: Standard Condition XIV directs the applicant to send copies of all application materials required to be submitted to the Department directly to the EPA, in electronic format if practicable. This condition shifts the burden of compliance from the Department to ensure that copies of application materials are submitted to EPA by transferring that responsibility to the Permittee.

Conditions 104 - 106, Permit changes and revisions requirements

Legal Basis: The Permittee is obligated to notify the Department of certain off-permit changes and operational changes under18 AAC 50.326(j)(4). 40 C.F.R. 71.6(a)(10), (12), and (13) incorporated by reference under 18 AAC 50.040(j) require these provisions within this permit. 40 C.F.R. 70 Appendix A documents that EPA fully approved the Alaska operating permit program effective November 30, 2001.

Factual Basis: These are conditions required in 40 C.F.R. 71.6 for all operating permits to allow changes within a permitted stationary source without requiring a permit revision.


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The Permittee did not request trading of emission increases and decreases as described in 71.6(a)(13)(iii).

Condition 107, Permit Renewal

Legal Basis: The Permittee must submit a timely and complete operating permit renewal application if the Permittee intends to continue stationary source operations in accord with the operating permit program under18 AAC 50.326. The obligations for a timely and complete operating permit application are set out in 40 C.F.R. 71.5 incorporated by reference in 18 AAC 50.040(j)(3). 40 C.F.R. 70 Appendix A documents that EPA fully approved the Alaska operating permit program effective November 30, 2001.

Factual Basis: In accordance with AS 46.14.230(a), this operating permit is issued for a fixed term of five years after the date of issuance, unless a shorter term is requested by the permit applicant. The Permittee is required to submit an application for permit renewal by the specific dates applicable to Healy Power Plant as listed in this condition. As stated in 40 C.F.R. 71.5(a)(1)(iii), submission for a permit renewal application is considered timely if it is submitted at least six months but no more than eighteen months prior to expiration of the operating permit. According to 71.5(a)(2), a complete renewal application is one that provides all information required pursuant to 40 C.F.R. 71.5(c) and with payment of fees owed under the fee schedule established pursuant to 18 AAC 50.400. 40 C.F.R. 71.7(b) states that if a source submits a timely and complete application for permit issuance (including renewal), the source’s failure to have a permit is not a violation until the permitting authority takes final action on the permit application.

Therefore, for as long as an application has been submitted within the timeframe allowed under 40 C.F.R. 71.5(a)(1)(iii), and is complete before the expiration date of the existing permit, then the expiration of the existing permit is extended and the Permittee has the right to operate under that permit until the effective date of the new permit. However, this protection shall cease to apply if, subsequent to the completeness determination, the applicant fails to submit by the deadline specified in writing by the Department any additional information needed to process the application. Monitoring, recordkeeping, and reporting for this condition consist of the application submittal.

Conditions 108 - 109, Permit Applications

Legal Basis: These conditions set out the protocol the Permittee must follow to submit amendment, modification and renewal applications to the Department under 18 AAC 50.326(c), 50.040(j)(3), and 40 C.F.R. 71.5, and to the Federal Administrator under 40 C.F.R. 71.5, 71.7 and 71.10.

Factual Basis: These conditions direct the Permittee to submit application materials to the Department’s Anchorage office. The current address at time of permit issuance is provided in a footnote because it may change during the life of this permit. The current address can be obtained by contacting the Department, checking the website, or by other reasonable means. The Permittee may submit copies of application materials in electronic formats compatible with ADEC software as the Department can more efficiently distribute the electronic copy to staff in other locations. Condition 109 directs the applicant to send copies of all application materials directly to the EPA, in electronic format if practicable.


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Conditions 110 - 114, General Compliance Requirements and Schedule

Legal Basis: These conditions ensure compliance with the applicable requirement in 18 AAC 50.326(j)(3). The Permittee is required to comply with these standard conditions set out in 18 AAC 50.345 included in all operating permits. 40 C.F.R. 70 Appendix A documents that EPA fully approved the Alaska operating permit program effective November 30, 2001.

No compliance schedule is included in the permit because GVEA certified that the Healy Power Plant was in compliance with all applicable requirements at the time of the renewal permit application.

Factual Basis: These are standard conditions for compliance required for all operating permits.

Conditions 115 - 116, Permit Shield

Legal Basis These conditions ensure compliance with the applicable requirement in 18 AAC 50.326(j) and apply because the Permittee has requested that the Department shield the source from the applicable requirements listed under this condition under the Federally approved State operating program effective November 30, 2001

Factual Basis: Table C of Operating Permit No. AQ0173TVP02 shows the permit shield that the Department granted to the Permittee. No requested shields were denied except for the new source review shield for Emission Unit 1. Since new source review may be triggered by physical or operational changes, prospectively during the life of the permit and is an applicable requirement for owner or operator, the Department cannot legally shield GVEA from that air quality control requirement. In addition GVEA has made burner replacements in the past that increased carbon monoxide emissions. The Department based the determinations on the permit application, past operating permit, construction permits compliance history and inspection reports.


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Attachment A

Pollutant (Circle One—SO2/NOX/fuel sulfur)

Reporting period dates:

From to

Company:

Emission Limitation

Address:

Monitor Manufacturer and Model No

Date of Latest CMS (CEMS and PEMS) Certification or Audit

Process Unit(s) Description:

Total source operating time in reporting period1

Figure 1 -- Summary Report -- Excess Emission and Monitoring System Performance

Emission data summary1 CMS (CEMS and PEMS) performance summary1

1. Duration of excess emissions in reporting period due to:

1. CMS (CEMS and PEMS) downtime in reporting period reporting period due to:

a. Startup/shutdown a. Monitor equipment malfunctions

b. Control equipment problems b. Non-Monitor equipment malfunctions

c. Process problems c. Quality assurance calibration

d. Other known causes d. Other known causes

e. Unknown causes e. Unknown causes

2. Total duration of excess emission 2. Total CMS (CEMS and PEMS) Downtime

3. Total duration of excess emissions X (100)/[Total source operating time] %2

3. [Total CMS (CEMS and PEMS) Downtime] X (100)/[Total source operating time] %2

1 For opacity, record all times in minutes. For gases, record all times in hours. 2 For the reporting period: If the total duration of excess emissions is 1 percent or greater of the total operating time or the total CMS (CEMS or PEMS) downtime is 5 percent or greater of the total operating time, both the summary report form and the excess emission report described in this condition shall be submitted.

On a separate page, describe any changes since last quarter in CMS, process or controls. I certify that the information contained in this report is true, accurate, and complete. Name

Signature

Issued: February 3, 2012 Healy Power Plant Expires: February 3, 2017

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APPENDIX A

GVEA Permit Applicability Determination for Resuming Operation of the

Healy Clean Coal Project (HCCP) 08-20-2009


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APPENDIX B

Issue Statement: Does a Prevention of Significant Deterioration (PSD) Review

Apply to the Restart of the HCCP? 10-12-2009


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APPENDIX C

I SEAN PARNELL, GOVERNORSTATE OF ALASKA ir/ PHONE: (907) 465-5100

DEPT. OF ENVIRONMENTAL CONSERVATION / FAX: (907)465-5129

DIVISION OF AIR QUALITY / TDD/TFY: (907) 465-5040

AIR PERMITS PROGRAM / htip://www.dec.state.ak.us

CERTIFIED MAIL: 7003 1680 0004 2909 4164Return Receipt Requested

August 20, 2009

Kristen DuBoisEnvironmental OfficerGolden Valley Electric Assoc.P0 Box 71249Fairbanks, AK 99707-1249

Subject: Permit Applicability Determination for resuming operation of the Healy Clean CoalProject (HCCP)

Dear Ms. DuBois:

In your May 26, 2009 letter, you asked the Department to confirm GVEA’s conclusion that theactivities GVEA will conduct to bring HCCP out of warm lay-up to fully operational condition willnot trigger Prevention of Significant Deterioration (PSD) review. We have reviewed all theinformation you have submitted regarding these activities. Based on that information, as well asapplicable state and federal law, policy and guidance, we concur that the activities do not constitutea major modification under the PSD program, and that resuming operation of HCCP does nottrigger EPA’s reactivation policy. Therefore, we agree with your conclusion that no PSD permit isrequired for these activities.

Although we reach the same conclusion, we may not agree with every point in the analysis that youprovided with your May 2009 letter. My staff is preparing a written technical analysis explainingthe basis of our conclusion, and we will include this analysis in the Statement of Basis for yourTitle V permit. In the meantime, if you have any questions about this matter, please call me at 907-465-5103.

Sincerely,

ohn F KuterbachAir Permit Program Manager

Cc:

via emailLarry Hartig, CommissionerAlice Edwards, DirectorPat Nair, EPA Region 10Nancy Helm, EPA Region 10

“Clean Air”

GVEAHealy Clean Coal Project (HCCP) August 20, 2009

via USPSMark Schimscheimer, P.E.Alaska Industrial Development and Export Authority813 W. Northern Lights Blvd.Anchorage, AK 99503-2495

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Golden Valley Electric Association (GVEA) Healy Clean Coal Plant (HCCP)

Issue Statement: Does a Prevention of Significant Deterioration (PSD) Review

Apply to the Restart of the HCCP?

Prepared by Cameron Leonard and Sally Ryan Final October 12, 2009

Reason for Analysis: On January 16, 2009, GVEA notified the Alaska Department of Environmental Conservation

(ADEC) and the U.S. Environmental Protection Agency that they had negotiated terms with the

Alaska Industrial Development and Export Agency (AIDEA) to transfer ownership of the HCCP

(a waste coal-fired boiler) from AIDEA to GVEA. In the notification, GVEA indicated that

Operating Permit AQ0173TVP021 authorizes GVEA to operate HCCP, and that they intended to

finally begin operations as soon as they checked out all the systems at the plant.

ADEC issued a PSD permit for construction and operation of HCCP in 1993 and revised the

permit in 1994. The unit operated briefly for testing purposes starting in early 1998 through late

1999 or early 2000. As of August 2009 the unit has been in warm shutdown for just over nine

years. A more detailed chronology of event is provided below.

On May 26, 2009, GVEA sent a letter to ADEC requesting a determination that PSD is not

applicable to startup of the HCCP.

This document summarizes pertinent project history and applicable law so as to frame this issue,

in order for ADEC to make a PSD applicability decision.

Stationary Source Description:

The Healy Power Plant is a not-for-profit electric power generating stationary source located in

Healy, Alaska. It is within six miles of Denali National park (a Class I area) and about 100 miles

from a soon to be designated PM-2.5 nonattainment area located in Fairbanks Alaska.

The Healy Power Plant is operated by GVEA. GVEA is the owner and the operator of Unit 1 and

the operator of HCCP. Unit 1 is a 25 MegaWatt (MW) coal-fired steam boiler, and HCCP is a 50

MW waste coal fired boiler. In addition to the boilers, the stationary source also contains two

1 This is a typo, as they are operating under AQ0173TVP01, Rev 2, under an application shield.

GVEA Healy Clean Coal Plant PSD Applicability Analysis October 12, 2009

2

Cleaver Brooks standby building heaters and one standby diesel generator, a crusher system, a

limestone silo with baghouse venting to atmosphere, a trona handling system with baghouse, a fly

ash silo with baghouse venting to atmosphere, and a coal handling system.

Chronology of Events:

The following is the chronology of events related to the HCCP as explained by GVEA in its letter

to ADEC dated May 26, 2009. Some of these incidents have not been independently verified, but

are presumed to be accurate. Those unverified statements are noted as such below.

December 1991 AIDEA and GVEA enter into a Power Sales Agreement (PSA), under which GVEA agrees to be operator of HCCP and to purchase all power from HCCP for 35 years once the plant achieves “commercial operations”. The PSA required a 90 day reliability test before January 1, 2000.

March 10, 1993 ADEC issues PSD Air Quality Control (AQC) Permit-to-Operate 9231-AA007. In this permit, ADEC determines that HCCP’s entrained combustion system is Best Available Control Technology (BACT) for Oxides of Nitrogen (NOX) and installed Sulfur Dioxide (SO2) controls were BACT for SO2 for the HCCP.

May 12, 1994 ADEC issues revised PSD AQC Permit-to-Operate 9431-AA001, which incorporates conditions of a Memorandum of Agreement (MOA) with US Department of Interior/National Park Service (NPS), Department of Energy (DOE), GVEA, and AIDEA.

January 1998 GVEA commences operations of HCCP. The unit reached full load for the first time in March of 1998. [UNVERIFIED]

March 1998 In March of 1998, AIDEA notifies GVEA that it did not intend to conduct or evaluate 90-day performance testing of the HCCP in such a way as to meet all requirements of PSA (and other agreements between parties). [UNVERIFIED]

May 1998 GVEA files suit against AIDEA seeking a court declaration of what PSA contract requires. [UNVERIFIED]

August 17, 1999 HCCP operates for 90 consecutive days (ending on November 15, 1999).

Late 1999 An independent engineering firm’s evaluation of 90-day performance test indicates exceedances of short term sulfur dioxide (SO2) emission limits and opacity requirements during startup, shutdown, and equipment repairs, The firm also concludes that HCCP had not met all criteria required to pass PSA’s 90 day test for commercial operations.

December 30, 1999 GVEA notifies AIDEA of its intent to terminate the PSA at midnight on December 31, 1999.

March 8, 2000 May 1998 suit settled under a Settlement Agreement effective March 8, 2000. This Agreement provides for an Interim Shutdown Period during which the plant will be temporarily shutdown while GVEA considers full retrofit to conventional coal burning or a limited retrofit (improvement to


3

clean coal technology). The agreement provided that the Shutdown Period would expire on the earlier of

● GVEA’s election to proceed with Retrofit work; or

● GVEA’s election to abandon efforts to obtain authorization to pursue Full Retrofit; or

● One year from the Turnover Date.

April 7, 2000 Interim Shutdown Period begins. [DATE UNVERIFIED.] GVEA begins discussion with Department to determine regulatory requirements for plant retrofit to more conventional technology. Discussions continued beyond expiration of one year period.

September 10, 2001 GVEA requests an administrative amendment of the Title V permit to allow a retrofit of the HCCP to replace the clean coal technology with low NOX burners.

April 11, 2002 Department denies the request for the administrative changes (to the Title V permit) to allow a retrofit. Department “unable to conclude that the proposed retrofit technology constitutes “equivalent” equipment under the regulations.”

April 2, 2003 GVEA formally terminates the PSA in April 2003.

April 2003 For a few months subsequent to PSA termination, GVEA continues to explore the possibility of a full retrofit of the HCCP and suggests to AIDEA the possibility of purchase of HCCP. [UNVERIFIED]

June 28, 2004 AIDEA notifies Department that AIDEA intended to act to “preserve its ability transfer the HCCP from GVEA to AIDEA (or a third party) and to pursue the continued operation of the HCCP with a limited retrofit of the clean coal technology.”

June 2004 Subsequent to the June 28, 2004 letter, AIDEA and GVEA began negotiations for an amended ground lease to allow AIDEA to operate HCCP, as provided in the Settlement Agreement. [UNVERIFIED.]

November 2005 While negotiating with GVEA for an amended ground lease, AIDEA sued GVEA to seek a court order requiring a ground lease and other agreements allegedly necessary for it to operate the unit. [UNVERIFIED.]

March 2006 HCCP Condition Assessment and Restart Study – HCCP/Unit 1 Independent Operations report prepared by Shaw, Stone & Webster (SSW) indicates that in 1999 “GVEA was contracted to perform plant maintenance to maintain HCCP in a standby condition and to prevent significant system and equipment deterioration.” In the report, SSW concludes that

● HCCP is in good condition and has incurred since 1999 no significant deterioration during the shutdown.

● If recommendations for remediation and system separation are implemented, SSW knows of no reason why HCCP cannot be operated separately from Unit 1 in a safe and reliable manner for the duration of its design life provided industry standard operation and maintenance activities are performed.


4

The report includes a list of high priority tasks (required prior to restart) and low priority tasks (may occur prior to restart but can occur later if at all.)

January 16, 2009 After years of discovery and mediation, the November 2005 litigation is stayed by AIDEA and GVEA by mutual agreement in January 2009. Under a settlement, GVEA has agreed to purchase HCCP and now intends to operate it as permitted, without a retrofit.

May 26, 2009 GVEA submits a letter to ADEC requesting a determination by Department that PSD is not applicable to startup of the HCCP. In the letter, GVEA estimates that costs of $1.125 million to $1.275 million would be incurred in bringing the HCCP into operation. GVEA estimates that the work would require seven to ten months to complete. GVEA also provide considerably higher estimates for additional work to conduct routine maintenance, safety reviews, evaluations, updates, and any necessary repairs and maintenance.

Legal Analysis:

The unusual factual scenario presented by the chronology of events outlined above comes down

to this: the actual start-up of the HCCP has been delayed for several years by protracted

disagreement and litigation between the two partners in the venture, GVEA and AIDEA. The

various positions taken by those two parties over the years can make the history of the stationary

source complicated, but the collective intent of the two partners has always been to eventually

operate the plant. Given the original cost of constructing the plant, to abandon the intent to ever

operate it would forfeit a considerable investment and defy common sense. ADEC does not

believe that either AIDEA or GVEA has ever abandoned the intent to operate the plant. The

delays in start-up are due instead to a difficult business negotiation between the parties over the

arrangements for the plant’s ownership and operation.

Governing Law:

Given this factual back-ground, the issue before ADEC is whether the long-delayed start-up of

the HCCP triggers the requirement for a new PSD permit. The governing state regulation is

18 AAC 50.3062. That regulation incorporates by reference the requirements of a federal

regulation, 40 CFR 52.21. Some of the relevant state definitions also incorporate definitions from

another federal regulation, 40 CFR 51.166. Thus, most of the legal analysis required to answer

2 The governing statutes are AS 46.14.120 and .130.


5

the issue before ADEC involves the terms and definitions contained in those two federal

regulations, which, incidentally, contain many parallel provisions.3

Of course, HCCP has already received a PSD permit, back in 1993. That permit, as subsequently

revised, remains in effect today. So the question is whether now starting up this permitted but

long-dormant plant triggers a second PSD permitting requirement. Under the regulatory terms,

the question is whether the proposed plant start-up should be treated and permitted as a “major

modification” of this stationary source. See 18 AAC 50.306(a); 18 AAC 50.990(53)(A); and 40

CFR 51.166(b)(2).

There are two prongs to the definition of a “major modification”: it can take the form of either a

physical change in the stationary source, or a change in the method of operation of the source. If

the start-up of HCCP qualifies as either (or both) of these two things, and also results in a

significant net emissions increase, then it is a major modification triggering PSD. Deciding

whether the plant start-up results in a significant net emissions increase also requires determining

what the base-line emission level is, to compare any increase to; that issue is dealt with below.

Finally, some changes in a stationary source are exempted from the definition of a major

modification. For our purposes, the two important exemptions are: (1) for “routine maintenance,

repair and replacement” (RMRR) of a source; and (2) for an increase in the hours of operation of

the source, if not prohibited by a federally-enforceable permit condition. The RMRR exemption

would apply to a physical change in the source, while the ‘increase in hours’ exemption would

apply to a change in method of operation of the source. Those exemptions, and their applicability

to HCCP, are discussed in turn below.

Major Modification Type 1: Physical Change in the Source.

The work GVEA proposes to do at the plant to start it up is summarized in Ex. 15 to their May

26, 2009 letter. GVEA updated Exhibit 15 on August 12, 2009 and August 17, 2009 to provide

information on the nature, extent, purpose, frequency, and cost of each activity proposed at the

plant. The work includes physical changes to the source, which GVEA claims fall within the

RMRR exemption. But before we reach the RMRR question, there is a threshold consideration:

would any of the physical changes that GVEA proposes actually result in an increase in emissions

from HCCP? It does not appear that the changes would result in increased emissions over what

3 40 CFR 51.166 spells out the PSD requirements for SIPs, while 40 CFR 52.21 includes largely equivalent elements for how EPA will administer the PSD program if a SIP is disapproved.


6

HCCP would have been emitting had it been operating. None of the physical work that GVEA

proposes to do appears to constitute “debottlenecking” (i.e.: resulting in an increase in utilization

of other units as a result of the project). Any expected increase in emissions will really be caused

not by the physical plant work itself, but rather by the commencement of plant operations, which

is analyzed below under the ‘change in method of operations’ prong of the major modification

definition.

Whether the proposed physical changes would also fall within the RMRR exemption is difficult

to determine, in part because the regulatory criteria governing that provision have been stayed by

court order. See Note to 40 CFR 51.166(b)(2)(iii)(A). If those criteria, found at 40 CFR

51.166(y), were in effect, then the work proposed by GVEA would appear to qualify as RMRR.

In the absence of this rule the Department must make the determination of whether the activities

proposed are RMRR on a case-by-case basis, using its best professional judgment. Based on

EPA guidance (WEPCO, September 9, 1988 and TVA September 15, 2000) the Department

considered the nature, extent, purpose, frequency, and cost of each proposed activity as provided

in GVEA’s August 17, 2009 Response to ADEC Request for Further Analysis.

The proposed activities at HCCP are divided into three categories. Category 1 includes all of the

proposed changes that are not related to operations that produce air emissions. Examples include

installation of ladders and access platforms, flushing the firewater system, and changing the

filters in the waste treatment system. Category 2 includes all of the proposed changes that are the

type of routine, ongoing maintenance and repair activities that occur at most utilities, and which

would have occurred at HCCP in an operational status at appropriate frequencies for that activity

regardless of whether related to a system that may produce emissions. Examples include

tightening bolts, lubricating moving parts, and repairing worn or damaged equipment. Some of

the activities listed include repairs of systems that were damaged by a coal explosion that

occurred in 1999. Because these activities listed in Categories 1 and 2 so clearly have no effect

on emissions, the Department did not review the activities in this category with regard to RMRR.

Category 3 consists of activities that are or may be related to systems that produce emissions.

Although (as stated previously) the Department believes that there are no emissions increases due

to these activities, we reviewed the nature, extent, purpose, frequency, and cost if each item to

assess whether they are truly RMRR. The Department first considered cost. HCCPs annual

maintenance costs are $14 million. With the exception of the replacement of mill exhauster fans

($2,000,000) and the investigation of a coal fines bypass system ($2,500,000), most of the


7

activities listed in Category 3 are RMRR simply based on cost. The Department looked at

replacement of mill exhauster fans and the investigation of a coal fines bypass system, items more

closely.

Replacement of Mill Exhauster Fan: The mill exhauster fan blades and scrolls eroded faster

than expected due to high ash content as abrasive properties of the Usibelli coal. The purpose of

this task it to evaluate installation of a new mill exhauster fan lined with a more abrasion resistant

material. GVEA expects future fan replacements to be less frequent due to use of a more robust

fan material and burning of better quality coal, along with ability to control fan speed.

Department analysis of Replacement of Mill Exhauster Fan: The Department finds the

replacement of the Mill Exhauster Fan to be RMRR based on purpose. The objective of this task

is to prolong the life of the fan. Any plant in operation would continually seek to reduce costs by

using components that will last longer. However, this replacement will not eliminate the need for

future replacements. This replacement will not affect plant performance or extend the life of the

plant.

Investigate Coal Fines Bypass System: Usibelli Coal Mine (UCM) produces large volumes of

coal fines as a result of crushing coal. HCCP and Unit #1 are the only power plants capable of

using UCM fines as a fuel, based on the types of fuel combustion systems at each plant.

Currently, all fines processed into the coal handling system must enter and pass through the

primary and secondary crushers. This task will investigate options for bypassing the crushers and

transport coal fines directly onto the conveyor belts that feed both Unit #1 and HCCP silos. This

will reduce handling costs and handling activities and should reduce dust emissions. This type of

analysis is the type of investigation regularly conducted by GVEA and other utilities into was to

minimize operational costs. The specific purpose of this investigation is to determine ways to

reduce the amount of time to load fuel and minimize labor costs in doing so.

Department Analysis of Investigation of Coal Fines Bypass System: The Department does

not find this to be RMRR. However, an investigation is not a physical change. It is a physical

change if the investigation results in a different way to bypass the crusher, and GVEA undertakes

this activity. A new bypass system does not appear to be RMRR. However, according to GVEA,

it “should reduce dust emissions” so the RMRR exemption is not necessary in order to find that

this does not fall under the definition of “major modification”.


8

We have already noted above that none of the activities listed by GVEA appear to be physical

changes that result in an increase in emissions. As such, the Department is only including this

discussion on the RMRR exemption for the sake of providing the most complete analysis

possible. The increase in emissions is caused by “turning on” a long dormant plant, which could

be considered to be a change in the method of operation. The change in the method of operation

to this plant is discussed below.

Major Modification Type 2: Change in Method of Operation.

Starting up the long-dormant HCCP plant seems, on its face, to be a change in the method of

operation. But GVEA advances two arguments for why such a change should not be considered a

major modification triggering PSD. First, GVEA argues that the baseline emissions level should

be calculated by reference to the plant’s potential to emit, rather than its actual past emissions

(which are essentially zero), so there is no increase in emissions due to plant start-up. Second,

GVEA argues that any emissions increase falls within the ‘increase in hours’ exemption

mentioned above. These two arguments are addressed in turn.

A. Baseline Emissions.

In order to be a major modification, a change in an existing stationary source must result in a

significant net emissions increase. See 40 CFR 52.21(a)(2)(iv)(a). To determine if there is a

significant net emissions increase, one compares projected actual emissions to baseline actual

emissions. See 40 CFR 52.21(a)(2)(iv)(c). For existing units, baseline emissions are usually

calculated based on historical emissions levels over a recent 24-month period. See

40 CFR 52.21(b)(48). However, because HCCP has never begun normal operations, we don’t

have historical data to work from. That makes calculation of baseline emissions levels less

straight-forward.

GVEA urges us, first, to extrapolate from the 90-day period of plant operations in 1999 to an

annual emissions level representative of baseline emissions. See GVEA’s 5/26/09 letter at p. 11.

But GVEA itself elected not to take over the HCCP based on the results of the ninety-day test run

in 1999. See Ex. 9 to GVEA’s 5/26/09 letter. GVEA’s recent claim that that test period does

reflect normal operation, and should provide the basis for extrapolated annual emissions, rings

hollow given their past decisions regarding this stationary source.

GVEA next argues that if we decide that the ninety-day emissions data do not represent normal

operations, then it follows that its baseline emissions should be set at its potential to emit rather


9

than its actual emissions, citing to 40 CFR 52.21(b)(48)(iii). There are two problems with this

argument. First, the approach of using potential to emit to set baseline emissions is for a ‘new’

emissions unit, not an ‘existing’ emissions unit. HCCP seems to fall within the latter definition,

since it has existed for more than two years since it first operated (i.e., during the 1999 test

period). See 40 CFR 51.166(b)(7). Second, even if we were to consider HCCP to be a new

emissions unit, the regulation requires us to use zero as the baseline for determining any

emissions increase “that will result from the initial construction and operation of such unit.” See

40 CFR 52.21(b)(48)(iii) (emphasis added). Since HCCP is only now starting up full, normal

operations, the appropriate baseline emissions level to use for purposes of evaluating the net

emissions increase is zero.

B. ‘Increase in Hours’ Exemption.

Even if we assume that the baseline emissions should be considered to be zero, for purposes of

evaluating the emissions increase that will result from plant start-up, the question remains of

whether the increased emissions are exempt from the definition of a major modification under 40

CFR 51.166(b)(2)(iii)(f), or the parallel regulation 40 CFR 52.21(b)(2)(iii)(f). Because the

proposed increase in hours of operation is not prohibited by any federally enforceable permit

condition, it appears on its face to fall within the scope of this ‘increase in hours’ exemption. But

certain EPA documents, referred to collectively as the “reactivation policy,” suggest that this

exemption may not be appropriate for a situation like HCCP’s, where a long-dormant stationary

source resumes, or in this case begins, operations. A discussion of EPA’s reactivation policy, and

whatever bearing it may have on our inquiry, follows.

However, as a threshold matter, it is worth noting that EPA policy documents do not have the

force of law, and there is no requirement that ADEC, or anyone else for that matter, follow them.

See, e.g., Appalachian Power Co. v. EPA, 208 F. 3d 1015 (D.C. Cir. 2005). Our consideration of

EPA’s reactivation policy simply serves as an exercise to help guide our understanding and

application of the governing regulations themselves.

EPA’s reactivation policy is generally contained in a 1999 decision by the EPA Administrator in

the Monroe Electric case. In that case, a power company proposed to restart a power plant that

had been shut down for 11 years due to market conditions. Louisiana issued the company an

operating permit without subjecting the facility to PSD review. A third party petitioned EPA to

review the state permit, arguing that PSD was triggered by the re-start of the plant.


10

EPA first noted that facilities that have been permanently shut down, and are then reactivated,

should be permitted as new sources. Whether a stationary source has been permanently shut

down “depends on the intention of the owner or operator at the time of shutdown.” See Monroe at

8. EPA established a presumption that a shutdown longer than two years was permanent, but it

allowed the stationary source owner or operator to rebut that presumption with evidence of their

intent to the contrary. Id. Having reviewed the history of HCCP, ADEC concludes that despite the

long delay in starting normal operations at HCCP, neither GVEA nor AIDEA have ever had the

intent of permanently shutting down this new plant. Those parties’ collective efforts both to keep

the facility’s permits current, and to maintain the plant in warm shut-down mode, reflect their

quite understandable intention to eventually operate HCCP.

The second part of EPA’s Monroe analysis applies to stationary sources that have not been

permanently shutdown, but simply long left dormant. EPA addressed the same question that

faces ADEC with regard to HCCP: does the start-up of such a stationary source constitute a major

modification triggering PSD review? In analyzing that question in Monroe, EPA considered both

of the regulatory exemptions discussed above, the RMRR and ‘increase in hours’ exemptions. In

evaluating the applicability of the latter exemption to the restart of a long-dormant facility, EPA

gave particular attention to whether the restart “would disturb a prior assessment of the

environmental impact of a source.” Monroe at 12 (citing to the preamble to its 1980 rule-

making.) For example, where the inactive source has been omitted from the state’s emissions

inventory, restart of that source would be less likely to qualify for the ‘increase in hours’

exemption. Id. at 12-13.

EPA concluded that the restart of the Monroe plant was a change is the method of operation that

did not qualify for the ‘increase in hours’ exemption, and therefore constituted a major

modification. In reaching its conclusion that the exemption didn’t apply to the Monroe restart,

EPA relied one two main factors: the plant’s emissions had not been included in the state’s

inventory; and the start-up of the plant did not seem like the kind of market-based change in

operations that EPA had intended the ‘increase in hours’ exemption to cover.

The first of these two factors is not present in the case of HCCP, as ADEC has continued to

include that in the state’s emissions inventory.4 But the second factor requires further discussion.

In reaching its conclusion about the intended scope of the ‘increase in hours’ exemption, EPA

4 Actually, ADEC included HCCP in its 1999 inventory, accidentally omitted it in 2002, and then included it again in 2005.


11

relied primarily on language in the preamble to the regulation, where it had described the purpose

of this exemption as protecting “the ability of a company to take advantage of favorable market

conditions” by increasing its hours of operation or rate of production. Monroe at 11-12, citing 45

FR 52704. EPA concluded that starting up the long-dormant Monroe plant was not the kind of

response to changing market conditions that the exemption was intended to insulate from PSD

review. Id. at 20-21.

While EPA’s policy documents may not govern our interpretation and application of the

regulations, we agree with EPA that the preamble to regulations is an appropriate interpretive aid

in understanding the intended scope of the accompanying regulations. Accordingly, ADEC has

independently reviewed the brief discussion in the preamble that addresses this exemption. On

balance, we do not interpret the preamble to create as narrow an exemption as EPA’s Monroe

decision would suggest. EPA stated in its preamble that the exemption “would exclude any

increase in hours or rate of operation, as long as the increase would not require a change in any

preconstruction permit condition established under the SIP.” 45 FR 52704 (emphasis added). It

noted that the Clean Air Act provisions on PSD permit requirements emphasized ‘construction’

activities rather than, presumably, operation of a source. Finally, EPA added that “any change in

hours or rate of operation that would disturb a prior assessment of a source’s environmental

impact should have to undergo scrutiny.” Id.

Based on the regulatory language of the exemption, and the entire (albeit brief) discussion of that

exemption in the preamble, ADEC reaches a conclusion in the HCCP case that is contrary to

EPA’s conclusion in Monroe. HCCP has already gone through PSD permitting, and its emissions

have been included in the state’s inventory during the years of its dormancy. For all we know,

the proposed start-up of HCCP is indeed a response to long-term market conditions (i.e.: the need

for more power in communities served by GVEA), and there is nothing in the preamble to

suggest that only short-term market trends were contemplated by the exemption. Given the

history of this stationary source and the governing regulatory language, ADEC concludes that the

start-up of HCCP under its existing permits falls within the ‘increase in hours’ exemption from

the category of major modification.

One final note: while it is tempting to regard HCCP’s PSD permit as somehow being ‘stale’, due

to the long delay in plant start-up, the federal regulations that deal with stale PSD decisions do

not appear to apply. Specifically, 40 CFR 52.21(r) essentially imposes an 18-month timeline for

commencing construction of PSD-permitted sources, as well as a duty to complete construction


12

“within a reasonable time.” The regulation does not impose a similar deadline or obligation for

commencing the operation of a permitted and constructed source. Thus, the long (and

presumably unusual) delay between the construction of HCCP and its proposed start-up does not

appear to make the original PSD permitting decision stale in any regulatory sense. Had EPA

chosen to require a prompt start-up of a constructed stationary source, it could have done so in a

way similar to the terms of its existing staleness rule. Having not done so, it appears to have left

more leeway for the delayed operation of a plant than for its delayed construction.

CONCLUSION:

For the reasons set out above, ADEC concludes that the long-delayed

commencement of the normal operation of the PSD-permitted HCCP does not constitute

a major modification triggering another PSD review. ADEC will proceed with on-going

Title V permitting of HCCP based on that conclusion.

APPENDIX C

Statement of Basis

AQ0173TVP02

GVEA Permit Applicability Determination

Commercial Startup of

Healy Clean Coal Project (HCCP) and Related Tasks

November 14, 2011

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Table of Contents for Appendix A

1. Background and Introduction .............................................................................................................. 3

a. History ............................................................................................................................................... 3

b. HCCP Startup .................................................................................................................................... 3

c. Physical Changes Proposed .............................................................................................................. 4

d. Unique HCCP Factors ........................................................................................................................ 4

e. Summary ........................................................................................................................................... 4

2. Tests to Determine if PSD Is Required ................................................................................................. 4

3. Physical Changes .................................................................................................................................. 5

a. Physical Changes Proposed .............................................................................................................. 5

b. Evaluation of Physical Changes ........................................................................................................ 6

i. Task by Task Evaluation ............................................................................................................... 6

ii. Evaluation of the Project as a Whole ........................................................................................ 12

4. Reactivation Policy and Changes in the Method of Operation ........................................................ 13

a. Reactivation Policy ......................................................................................................................... 13

b. Hours of Operation Exemption to Changes in the Method of Operation .................................... 17

i. Monroe Power and Cyprus Casa Grande Decisions .................................................................. 17

ii. HCCP differences from Monroe Power and Cyprus Casa Grande Decisions and Reasons for

Applying the Hours of Operation Exemption ..................................................................................... 17

c. ADEC Conclusions Regarding Changes in the Method of Operation ............................................ 20

5. Major modification and Significant Net Emissions Increase Calculations ....................................... 20

a. Test for an Existing Emissions Unit ................................................................................................ 20

b. Selection of the Time Period for Baseline Actual Emissions ......................................................... 21

c. Potential to Emit as Baseline Actual Emissions (BAE) ................................................................... 21

d. BAE/PAE Test Based upon 90‐Day Test Period ............................................................................. 23

i. Rationale for Selecting Another Time Period for Baseline Actual Emissions ........................... 23

ii. BAE and PAE Calculations and Methodologies ......................................................................... 24

iii. Effect of Other Assumptions for Emission Factors .................................................................... 27

iv. Possible Exclusions ..................................................................................................................... 27

e. Conclusions from Calculations ....................................................................................................... 29

6. ADEC Findings Regarding PSD Applicability ...................................................................................... 30

7. Task Lists ............................................................................................................................................. 31

8. Chronology of Events ......................................................................................................................... 58

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1. Background and Introduction

Golden Valley Electric Association (GVEA) and the Alaska Industrial Development and Export Authority (AIDEA) intend to bring Healy Power Plant Unit 2, also known as the Healy Clean Coal Project (HCCP), on line to generate electric power commercially. This intent thus far has not been achieved. At issue is whether HCCP must go through PSD permitting a second time before commercial operations commence. The Alaska Department of Environmental Conservation (ADEC) authorized Healy Power Plant Unit 2 (HCCP) and support emission units under PSD and constructed as described in the history portion of this Appendix. a. History

In December 1990, the HCCP owner, AIDEA and GVEA entered into a Power Sales Agreement (PSA) under which GVEA agreed to operate HCCP and purchase all power from HCCP once the plant achieves commercial operations. The agreement called for a 90 day test period.

ADEC issued HCCP a PSD permit March 10, 1993. The National Park Service appealed ADEC’s decision. On May 12, 1994, ADEC issued a revised PSD permit, which incorporated a Memorandum of Agreement (MOA) with the National Park Service, Department of Energy, GVEA, and AIDEA. ADEC is not a party under this MOA.

In January 1998, the owner and operator started up and began testing HCCP. HCCP used experimental slagging combustor technology coupled with direct limestone injection into the combustion zone for NOx, particulate and Sulfur dioxide emissions controls. HCCP operated intermittently in 1998 and 1999. After completion of the 90-day test period in November 1999, AIDEA then placed HCCP into warm shutdown while AIDEA and GVEA, attempted to reach agreement on how best to operate the unit. The next 10 years were characterized by a series of agreements and lawsuits between these two parties.

On January 16, 2009, GVEA notified ADEC and U.S. Environmental Protection Agency (EPA) that GVEA negotiated terms with AIDEA to transfer HCCP ownership from AIDEA to GVEA. In that notice, GVEA indicated that Operating Permit AQ0173TVP01 still authorizes GVEA to operate HCCP. GVEA also indicated that they intended to commence commercial operations as soon as they checked out all the HCCP systems.

A more detailed chronology of events is provided in Table E of this Appendix.

b. HCCP Startup

HCCP consists of a boiler emissions unit (Unit 2) and several support emission units (including coal handling equipment and ash handling equipment). In conjunction with Unit 2 startup, GVEA proposes a list of tasks described in Section 6, Table B through Table D. This list includes both tasks that affect related emissions units and tasks that do

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not affect emissions units. More detail is provided in the Physical Changes in Section 3(a).

c. PSD Applicability Request

Although GVEA currently has an operating permit that authorizes operation of Unit 2, GVEA wants to eliminate doubt that ADEC or others would assert that HCCP commercial startup triggers PSD. On May 26, 2009, GVEA sent a letter to ADEC requesting a determination that PSD is not applicable to commercial startup of the HCCP boiler. In that letter GVEA also described maintenance, repair, and upgrade tasks that GVEA intends to perform before and during commercial startup. Many tasks would reportedly have been done over time under HCCP's maintenance budget had Unit 2 operated during the period from 1999 until now.

d. Unique HCCP Factors The Healy Power Plant is an existing Major Stationary Source GVEA has operated

continuously since 1967. ADEC considered construction of HCCP as a major modification, and permitted

construction under PSD in 1993 and 1994 under the State Implementation Plan approved pre-construction review program (18 AAC 50 effective at that time).

HCCP Unit 2 never achieved normal operations. Instead AIDEA shut down this emissions unit upon completion of the 1999 90-day performance testing.

As agreed to through the 1994 MOU, GVEA retrofitted the Power Plant’s existing Unit 1 to offset NOx, PM, and SO2 emissions increases anticipated for HCCP Unit 2.

GVEA plans no change to the clean coal technology controls installed on HCCP, nor does GVEA plan changes to increase the duty rating of the boiler.

e. Summary

As described in this attachment, ADEC has found that commercial startup of HCCP does not require another PSD permit.

2. Tests to Determine if PSD Is Required

A PSD permit would be required if HCCP Unit 2 commercial operations would be defined as a major modification to a major stationary source. It is not disputed that the GVEA Healy Power Plant is a major stationary source as defined in the State and federal PSD programs which rely upon a similar definition.

Stationary source means any building, structure, facility, or installation which emits or may emit a regulated NSR pollutant. [40 C.F.R. 52.21(b)(5)] Building, structure, facility, or installation means all of the pollutant-emitting activities which belong to the same industrial grouping…(emphasis added)[40 C.F.R. 52.21(b)(6)]

ADEC then must examine whether the project is a major modification to the Power Plant.

A major modification means any physical change in or change in the method of operation of a major stationary source that would result in a significant emissions

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increase of a regulated NSR pollutant… and a significant net emissions increase… (emphasis added) [40 C.F.R. 52.21(b)(2)(i)] A significant emissions increase of a regulated NSR pollutant is projected to occur if the sum of the difference between the projected actual emissions …and the baseline actual emissions … for each existing emissions unit, equals or exceeds the significant amount for that pollutant [40 C.F.R. 52.21(a)(2)(iv)(c)]

The project would subject HCCP to PSD permitting again if the project were found to be subject to EPA's reactivation policy for a stationary source that has shut down. If subject, the power plant would be considered a new stationary source.

To conclude that PSD does not apply, ADEC examined the project in its entirety to determine whether commercial operations of HCCP Unit 2 and related tasks could be classified as another major modification. First, ADEC examined the physical changes associated with the project. Then, ADEC examined whether the project subject to EPA’s reactivation policy. Finally, ADEC examined the project to see if it is defined as a change in the method of operation.

In the event of a permit appeal, ADEC took the final step to determine the project’s net emissions increase in its entirety and to show that the increase is not significant.

Physical Changes

The PSD regulations do not define "physical change." Instead they describe activities that are not considered physical changes; most notably, the regulations exclude routine maintenance, repair and replacement--RMRR.

A physical change or change in the method of operation shall not include:

(a) Routine maintenance, repair and replacement... [40 C.F.R. 52.21(b)(2)(iii)(a)]

a. Physical Changes Proposed

Unit 2 start-up is not a physical change. However, before starting commercial operation GVEA proposes to perform a list of tasks that may be construed as physical changes. Tasks are based on the March 2006 report by Shaw, Stone & Webster, and subsequent evaluations by GVEA. GVEA summarized the work in Exhibit 15 of their May 26, 2009 letter. GVEA made subsequent revisions to the task list. The currently planned tasks are listed in Table B - Table D of Section 6 of this Appendix.

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b. Evaluation of Physical Changes

ADEC evaluated the tasks both individually and collectively. To trigger major modification PSD based upon physical changes to a stationary source, the changes must cause an emissions increase that is equal to or greater than the significance threshold for that pollutant in 40 C.F.R. 52.21(b)(23).

ADEC evaluated each of the proposed tasks as follows:

Does the task result in an emissions increase? Is the task a physical change to a pollutant emitting activity (emissions unit)? Is the task routine maintenance, repair, or replacement?

ADEC then evaluated whether the physical changes taken as a whole constitute a major modification requiring PSD review.

ADEC concluded the following.

Most of the tasks taken individually would constitute routine maintenance and repair, or are not physical changes to pollutant emitting activities.

The remainder of the tasks will not result in emissions increases.

Although over-reaching, total emission increases from all tasks, including those that are exempt as routine maintenance, repair or replacement, and those that are not physical changes to pollutant emitting activities will still not result in a significant emissions increase for any NSR pollutant.

i. Task by Task Evaluation

1. Routine Tasks (Table B)

Table BTable B lists tasks that ADEC finds to be routine maintenance repair and replacement (RMR&R) included under the exemption of 40 C.F.R. 52.21(b)(2)(iii)(a). As such they would not be considered physical changes or changes in the method of operation. None will cause an increase in the emission unit’s potential to emit. ADEC found only two (Tasks E.2 and H.1) that could cause an increase in actual emissions and of only PM-10. However, the total actual emissions increase would be less than 5 tons per year (tpy) of PM-10.

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a. RMR&R Criteria

The following excerpts from Advanced New Source Review Manual1 (p 156) give criteria for deciding whether physical changes are routine.

In the brief for the WEPCO decision EPA outlined five interrelated factors for determining whether a project is routine. None of these factors – standing alone – conclusively determines a project to be routine or not. Instead a permitting authority should take account of how each of these factors might apply in a particular circumstance to arrive at a conclusion considering the project as a whole.

Nature

Whether major components of a facility are being modified or replaced; specifically, whether the units are of considerable size, function, or importance to the operation of the facility, considering the type of industry involved

Whether the change requires pre-approval of a state commission in the case of utilities

Whether the source itself has characterized the change as non-routine in any of its own documents

Whether the change could be performed during full functioning of the facility or while it was in full working order

Whether the materials, equipment and resources necessary to carry out the planned activity are already on site

Extent

Whether an entire emissions unit will be replaced

Whether the change will take a significant time to perform

Whether the collection of activities taken as a whole, constitutes a non-routine effort, notwithstanding that individual elements could be routine

Whether the change requires the addition of parts to existing equipment

Purpose

Whether the purpose of the effort is to extend the useful life of the unit; similarly, whether the source proposes to replace a unit at the end of its useful life

Whether the modification will keep the unit operating in its present condition, or whether it will allow enhanced operation (e.g., will it permit increased capacity, operating rate, utilization, or fuel adaptability)

1 Gary McCutcheon. RTP Environmental Associates. 2009.

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Frequency

Whether the change is performed frequently in a typical unit’s life

Cost

Whether the change will be costly, both in absolute terms and relative to the cost of replacing the unit

Whether a significant amount of the cost of the change is included in the source’s capital expenses or whether the change can be paid for out of the operating budget (i.e., whether the costs are reasonably reflective of the costs originally projected during the source’s or unit’s design phase as necessary to maintain the day-to-day operation of the source.)

b. Comparison of Tasks to the RMR&R Criteria

Nature

Based on cost, two major components are to be replaced. But both of these can reasonably be considered routine. These are the computer system’s human interface, and the mill exhauster fans.

These components could be considered major components based on the cost of the replacements ($470,000 and $2 million respectively).

Computer System - Human machine Interface (HMI): GVEA’s equipment provider estimates for similar power plants, HMI’s are typically replaced in 10 – 12 years. More frequent change outs than in the past are expected with digital systems. Unit 1’s HMI has been replaced twice. The change to HCCP would mean both units are using the same system. GVEA’s vendor no longer supports the existing HCCP system.

Mill Exhauster Fans: The fans would be replaced with more abrasion resistant fans. According to GVEA, replacement will be necessary a number of times during the life of the plant, regardless of whether the new fans are of a longer lasting material. Replacement with a more resistant material, given what has been learned about the abrasive nature of the coal used will decrease the frequency of replacement. Future replacements would presumably also be of more resistant material.

GVEA has not characterized any of the tasks as non-routine. GVEA states that none of the physical changes on their list is necessary before the restart. But it is obviously the most convenient time, while it is not running.

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Extent

No task will replace an entire emissions unit except the slag ash grizzly.

Taking the project as a whole, most of the tasks are routine or the tasks are not considered physical changes; the rest are intended to improve the efficiency of operation. Some may help GVEA reduce air emissions below levels achieved during the test phase. None are essential to restart. ADEC finds it reasonable to exclude those tasks that are routine from further consideration. Doing so would not change the overall conclusion.

The entire collection of tasks will take significant time to perform. In his comments, Brian Newton, President and CEO of GVEA estimated that tasks will take between seven and fourteen months.

Purpose

None of the tasks involve a life extension project, as described in EPA guidance.

None of the tasks would increase capacity, or operating rate.

None of the tasks are essential to commercial operation, so none are intended to increase utilization over what would occur without the task.

Frequency

Some tasks would be done periodically. Routine tasks that would be done once are evaluated further in Table B. Many of these could be done over time under a maintenance budget, but GVEA finds it financially and operationally more advantageous to do so now.

Some of the tasks are one time installation of new hardware, or one time design changes to correct a flaw or otherwise improve operation. Many of these are, however, routine in nature. Some tasks make one time changes at particular locations, but are the types of changes that go on routinely throughout a power plant. These types of tasks include

installation of new valves and associated hardware;

re-routing material handling devices; and

tasks not associated with emissions, and that are intended to assure compliance with applicable codes such as safety, fire, and electrical codes, or that otherwise assure plant safety.

Cost

Absolute: GVEA lists the absolute cost of all planned tasks together at $11 million. For this plant it is less than the projected annual maintenance

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budget of $14 million, so each individual task is within that projected budget as well. $11 million is greater than costs EPA has considered significant. However, GVEA’s costs at Healy Alaska are not generally comparable to operations in less remote areas that EPA oversees.

Relative: At approximately 4% of the new unit cost, the total project budget is less than less than the 6% considered routine for International Paper Ridgewood Mill. WEPCO was 15% and Cyprus Casa Grande was 10%. (WEPCO and Cyprus were non-routine.) Since the total project cost is only 4%, each of the individual tasks will be below 4%.

Many of the tasks would normally be spread over a number of years under operation and maintenance budgets. However, due to the nature of this restart, these tasks will occur at one time. Other tasks are intended to make maintenance activities more efficient, or otherwise reduce costs. They would be done now because GVEA has had years to evaluate the HCCP engineering studies that identify ways to run Unit 2 more efficiently. While the plant could be restarted without the improvements, it makes sense to proceed with recommended efficiency projects. It makes greater sense considering the nature of AIDEA’s proposed funding of the HCCP sales agreement.

c. Tasks That May Increase Emissions

Two tasks that ADEC considers routine maintenance, repair and replacement tasks could cause increases in particulate matter emissions. These are Task E.2, addition of a vibrator to a coal bucket elevator emissions unit, and Task H.1, replacement of the slag ash grizzly with a clinker grinder emissions unit. i. E.2 Vibrator

The coal bucket elevator is a separate support emissions unit with a transfer point that is hooded and controlled by a baghouse for particulate emission control. The planned vibrator device will be designed so that each rap can be programmed individually. The device is planned to jar loose coal that has clogged the elevator due to coal moisture (wetness and ice). When not needed during periods when the coal and dust lacks moisture to adhere to the elevator, the vibrator would not be used. During the times when it is used, there would be little dust generated because of the coal moisture. The transfer point where any emissions would be emitted is hooded and vented to an existing fabric filter – emission unit number 10 control device, listed in the permit. That emission unit has an existing limit on its potential to emit of 5 tpy PM. Any emission increase

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from this task must be less than the 5 tpy PM-10 potential emissions as capped and controlled by the baghouse.

ii. H.1 Clinker Grinder

Since the clinker grinder emission unit replaces the existing grizzly emission unit, the clinker grinder, is not included under any of the emission units listed in Table A of the draft operating permit. If there are any emissions, the grinder would be a new emission unit. Since the clinkers are quenched before transfer to the grizzly, the clinkers will be wet when processed, and therefore unlikely to produce emissions. EPA’s emission factor in AP-42 Table 11.19.2-2 for crushed stone operations is given as non-detect for primary crushing even for uncontrolled crushers. Therefore, ADEC concludes that this source would not contribute to an emission increase. Since emissions are non-detect, this grinder would be an insignificant emissions unit. ADEC is not required to list such units in the operating permit.

d. Parasitic Loads

Parasitic load is the electrical energy generated, but used internally to run the plant, rather than being available for sale. Several of the tasks would increase internal electrical use, and therefore increase parasitic load. Some tasks would decrease electrical use. Overall, GVEA estimates that the total projected increase in parasitic load is 0.0014% of the total plant electrical usage (7.5 MW). That fraction of the total load would correspond to about 4 pounds per year of NOX, the worst case pollutant. However, GVEA also states that both Units 1 and 2 are base load units. When on line they will be operating at full capacity. An increase in parasitic load would not increase the power generated or actual emissions. It would only minimally decrease the amount of power available for external sale. Therefore, an increase in parasitic load does not constitute a modification increasing actual emissions.

2. Tasks That Are Not Modifications for Other Reasons ‐ Table C

Table C lists tasks that are not physical changes to the stationary source. One task is a fluid dynamics study with no changes planned at this time. Another task is not a change from operation during the test phase. The rest cannot be part of a

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major modification, because they are not changes to the pollutant emitting activities. See the definitions of stationary source and building, structure, facility, or installation above. [40 C.F.R. 52.21(b)(5) and (6).] Examples are adding signs, labels, and improved access such as stairs. Table B - D include a column denoting whether the task is exempt because it does not affect a pollutant emitting activity. All tasks in Table C are marked Y as they clearly are exempted for this reason. Tasks the other tables are not exempt for this reason, or whether they are is unclear.

This exemption is in addition to other exemptions, such as routine maintenance, repair or replacement.

3. Efficiency Improvements Project ‐ Table D

Table D lists the remainder of the tasks referred to in this Attachment as the Efficiency Improvement Project. These tasks constitute the project that is compared against the PSD applicability criteria for a major modification due to physical changes to a major stationary source. Table D lists the reasons why each task of the efficiency improvement project is not critical to commercial startup, but is intended to improve the efficiency of its operation.

ADEC compared the efficiency improvements project listed in Table D to the applicability criteria of 40 C.F.R. 52.21(a)(2). Those tasks do not cause emissions, are not essential to restarting HCCP, and are not debottlenecking relative to any other emitting activity, or to the restart as a whole. None of these tasks would result in an increase in actual emissions from the physical change.

ii. Evaluation of the Project as a Whole

Regardless of whether the project includes just the tasks listed in Table D, or all of the planned tasks listed in Table B through Table D, cumulative emission increases do not approach PSD significance thresholds.

Only the two tasks mentioned above, E.2 and H.1, (Table B), could cause PM-10 emission increases. ADEC considers both tasks as routine. Even if not considered routine the PM-10 emissions increase of both emission unit changes (up to 5 tpy) would be much less than any PSD construction permit threshold. This value will be considered later with the net PM-10 emissions increase of Unit 2 to show the total emissions increase would not exceed the PSD significance threshold.

ADEC finds that GVEA’s planned tasks in conjunction with HCCP Unit 2 commercial operations do not constitute physical changes that would trigger PSD review.

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3. Reactivation Policy and Changes in the Method of Operation

a. Reactivation Policy

EPA affirmed the reactivation policy when considering the restarts of both the Monroe Electric2 and Cyprus Casa Grande3 plants4. EPA’s reactivation policy as outlined in Monroe5, is that reactivation of a major stationary source that has been permanently shut down, will be treated as construction of a new stationary source for PSD review. What constitutes permanent shut down also depends on the intent of the owner or operator. The policy has a rebuttable presumption that if the major stationary source shut down has lasted more than two years it is presumed to be permanent. Due to the rebuttable presumption and the intent of the owner as factors, each reactivation case should be reviewed case-by-case. In Monroe, EPA states, “reactivation of facilities that have been in an extended condition of inoperation may trigger PSD requirements.” (Emphasis added)

The permitting agency assesses whether the owner or operator has demonstrated a continuous intent to reopen based on several factors such as:

1. the amount of time the plant has been out of operation, 2. the reason for the shutdown, 3. statements by the owner or operator regarding intent, 4. cost and time required to reactivate the plant, 5. status of permits, and 6. ongoing maintenance and inspections that have been conducted during shutdown.

HCCP and Reactivation:

1. Stationary source versus emissions unit

HCCP Unit 2 is a single boiler within the Healy Power Plant. The plant constitutes the stationary source. The reactivation policy does not extend to a single existing emission unit within a stationary source. ADEC is unaware of

2 Order Responding to Petitioner’s Request… Carol Browner, EPA Administrator. In the Matter of Monroe Electric Generating Plant Entergy Louisiana, Inc. Proposed Operating Permit. Petition No. 6-99-2. 3Letter from David P. Howekamp, Director EPA Region IX, Air Management Division to Robert T. Connery, Holland & Hart, November 6, 1987. Re: Supplemental PSD Applicability Determination Cyprus Casa Grande Corporation Copper Mining and Processing Facilities. 4 In Monroe, EPA expressed "serious doubts" about the owner's continuous intent to restart, but did not make a

finding under their "reactivation policy" using it because they didn't need it after making a finding that restart was a change in the method of operation. EPA found Cyprus to be subject to PSD under both provisions. 5 Monroe Elec. Generating Plant, Pet. No. 6-99-2, at 9

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guidance or precedent for EPA to expand this policy or to apply the existing policy down to the emission unit level. Historical ADEC precedent allows continued or renewed operation of units not in operation without triggering PSD review if the Permittee so desires. ADEC acknowledges that these precedents do differ from HCCP Unit 2 in that they typically apply to obsolete inefficient diesel generator set units retained on site for use in the event of newer unit failure.

2. Amount of time in shutdown

HCCP Unit 2 has been in warm lay-up since its initial construction and preliminary startup testing that concluded in late 1999.

HCCP Unit 2 has never been in commercial operation. It did, however, generate and sell generated power while undergoing shakedown and performance testing in 1998 and 1999.

3. Reason for shutdown During the course of preliminary testing, a dispute arose between GVEA and AIDEA regarding the 1990 power sales agreement, which began a 10-year litigation and settlement process between the parties. This commercial startup effort is intended to resolve the parties' differences with the intent of starting operation of HCCP Unit 2and recouping the value of HCCP the investment.

4. Statements by the owner (AIDEA) or operator (GVEA)

AIDEA initiated litigation and engaged in settlement to recoup the value invested in HCCP.

Statements made in the late 1990s by commentators regarding GVEA's reservations about the technology and its ability to reach commercial operation does not demonstrate an intent to permanently shut down the emission unit. Those statements merely reflect the nature of the dispute between the parties.

Mark Schimscheimer, AIDEA’s HCCP Project Manager, in his comments on this permit (Comment 8) stated:

“Though time has passed since the HCCP was last operated, AIDEA affirms that it has tirelessly worked to achieve timely start of commercial operations. There is simply no basis for any party to legitimately challenge AIDEA’s long-term commitment of management and staff effort and financial resources in bringing this valuable state electrical generating asset back into operation.”

ADEC has not found evidence that would rebut Mr. Schimscheimer's comment as agent of the owner.

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5. Cost and time to reactivate

GVEA will use prudent utility practices to ensure the proper startup of HCCP. Costs of completing priority startup activities could be about $11 million. GVEA will use mainly in-house labor. Priority activities could be completed in approximately seven months.

6. Status of permits

All permits have remained active during the idle period. GVEA and AIDEA received the Healy Power Plant’s first operating permit No. AQ0173TPV01 in 2003. All permitting fees are paid. The Monroe Power Plant shut down before the State’s operating permit programs was in effect, and would not have needed to get an operating permit when shut down.6 The first operating permit for Healy was issued in 2003 after HCCP Unit 2 was shut down. Had Unit 2 been permanently shut down, the Healy Power Plant operating permit would not have needed to include HCCP Unit 2 and terms for operation. However GVEA did apply for and obtain an operating permit with terms that authorized on-going operations of HCCP, thus signaling their intent to operate HCCP Unit 2.

7. Ongoing maintenance and inspections

GVEA reports spending $20 million since January 2000 to maintain HCCP in warm lay-up status pursuant to custodial agreements between AIDEA and GVEA. Under these agreements, measures are routinely undertaken to ensure HCCP Unit 2’s readiness to operate, including the following:

Major equipment is rotated at intervals as required by suppliers. Equipment and materials are lubricated and protected. HCCP is protected from extreme weather conditions. Internal pressure part surfaces are isolated with dry air blanket to prevent

deterioration. Fire, safety, and security systems are maintained and periodically tested and

operated. Periodic inspections of HCCP equipment are conducted. AIDEA continuously maintained hot standby insurance coverage on HCCP. No components of HCCP were decommissioned in any way.

In contrast, the Monroe decision document described maintenance done as primarily responding to problems with the dehumidification system.

6 For Cyprus, both the shutdown and the planned restart were before Title V, so there is no basis for comparison on that element.

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8. Development of a temporary shutdown plan to maintain the source so that it would be available when market conditions change.

The March 2000 Settlement Agreement between AIDEA and GVEA required the parties to develop a transition plan which required, among other things, that the parties provide for the maintenance of HCCP. The parties thereafter entered into a Custodial Agreement which requires GVEA to maintain HCCP Unit 2 in accordance “with Prudent Utility Practices and in compliance with the GVEA lay-up plan and manufacturer’s recommendations for maintenance.”

9. Maintaining the source as active and part of the State's emission inventory

HCCP Unit 2 is active and is still maintained as part of the State's emission inventory. Monroe and Cyprus were not.

10. Maintenance of employees on‐site7

Trained operators provide 24-hour coverage of HCCP Unit 2. The Monroe decision document described the plant as in "'unmanned' condition".

11. Entering negotiations to sell assets or re‐organize the company

AIDEA's litigation and the joint settlement is intended to resolve the differences between the two parties so that HCCP Unit 2 can be placed into commercial operation.

12. Cost of initial investment

The various positions taken by the two parties over the years can make the history of the emission unit complicated, but AIDEA’s intent has always been to eventually operate HCCP Unit 2. Given the original cost of constructing the emission unit, to abandon it would forfeit a considerable investment and defy common sense.

This is a very different circumstance from Monroe, Cyprus, or any of the other stationary source reactivations. For those cases, the initial investment had already been recovered by years of operation. This conclusion is further supported by information presented in section 3.b.ii of this document. Please refer to that section.

7 Criterion from Memorandum from John B. Rasnic to Douglas M. Skie regarding Watertown Power Plant(Nov. 19, 1991)

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ADEC believes that neither AIDEA nor GVEA abandoned the intent to operate the emission unit. On multiple occasions since 2000, AIDEA and GVEA worked with ADEC’s Division of Air Quality to bring HCCP Unit 2 back into operations. The delays in start-up are due instead to a difficult business negotiation between the parties over the arrangements for the emission unit’s long term ownership and operation. Therefore, ADEC concludes that the reactivation policy and associated PSD permitting as a new stationary source do not apply to HCCP Unit 2 commercial startup.

b. Hours of Operation Exemption to Changes in the Method of Operation

40 C.F.R. 52.21 (b)(2)(iii)(f) exempts "an increase in the hours of operation or in the production rate, unless such change would be prohibited under any federally enforceable permit condition…" 45 FR 52704 presents guidance for the use of this exemption. The criteria given in that federal register include: The increase would not require a change in any preconstruction permit condition

established under the SIP; and No prior assessment would be disturbed by the increased operation HCCP Unit 2. The federal register also gives an example for use of the exemption in response to favorable market conditions.

i. Monroe Power and Cyprus Casa Grande Decisions

ADEC received comments from EPA Region X concerning ADEC’s comparison of HCCP Unit 2 to Monroe Electric8. EPA claims similarities between Monroe and HCCP relative to hours of operation exemption. Trustees for Alaska also claimed similarities between HCCP and the Cyprus Casa Grande9 decision.

In the Monroe decision, the EPA administrator determined that issuance of a Operating Permit was not in compliance with PSD. The Monroe Electric Generating Plant had been shut down for 10 years and was to be restarted. The administrator found that restarting the Monroe plant would constitute a significant increase in regulated emissions because it was a change in the method of operation. EPA ruled that the hours of operation exemption did not apply. Regarding Cyprus Casa Grande, EPA found that restarting the stationary source was a major modification because the restart was accompanied by physical changes and a change in the method of operation. Cyprus Casa Grande had also been shut down for 10 years.

ii. HCCP differences from Monroe Power and Cyprus Casa Grande Decisions and

Reasons for Applying the Hours of Operation Exemption

8 Order Responding to Petitioner’s Request… Carol Browner, EPA Administrator. In the Matter of Monroe Electric Generating Plant Entergy Louisiana, Inc. Proposed Operating Permit. Petition No. 6-99-2. 9Letter from David P. Howekamp, Director EPA Region IX, Air Management Division to Robert T. Connery, Holland & Hart, November 6, 1987. Re: Supplemental PSD Applicability Determination Cyprus Casa Grande Corporation Copper Mining and Processing Facilities.

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Having considered Monroe and Cyprus, ADEC finds that HCCP is subject to the hours of operation exemption and does not need a second PSD review as a change in the method of operation for the following reasons.

HCCP is fundamentally different from both Cyprus and Monroe Power cases. For the reasons given in Sections 1.d,, 3.a, and this Section--especially because AIDEA has embarked on continuous efforts to bring HCCP into initial commercial operation, and because HCCP already underwent PSD without yet achieving that operation, ADEC finds that the HCCP circumstances are fundamentally different from other circumstances for which EPA has generated guidance related to that Federal Register. Because EPA has not made any rulemaking or developed implementing guidance that’s germane and applicable to HCCP Unit 2, ADEC finds that it is acceptable to rely on the Federal Register language. Further, it is unlikely that Congress’s intent, for a single emission unit so delayed despite its owner’s persistent continued efforts, would have been required to go through a second PSD pre-construction review to start viable commercial operations. Finally, after-the-fact preconstruction review in this case would impose unreasonably greater increase in control technology costs to retrofit the Unit 2 Boiler. For HCCP, imposing a second review would further delay commercial start-up. Commercial start-up of HCCP Unit 2 satisfies each criteria identified in the Federal Register preamble which established the “hours of operation” exemption from changes in the method of operation [45 FR 52704]. The preamble stated that the exemption “would exclude any increase in hours or rate of operation, as long as the increase would not require a change in any preconstruction permit condition established under the SIP.” The final operating permit will not change any preconstruction permit conditions. No construction or modification activities will require additional Air Quality permitting. Unit 2 commercial startup would also not disturb any previous environmental assessment. Unlike Healy Power Plant and HCCP Unit 2, the Monroe and Cyprus plants were deleted from state emissions inventories, and neither could show that there was a continuous intent by its owner to get it into operation rather than permanently shutting down.10

The Ozone Transport Assessment Group (“OTAG”) used Monroe’s zero emissions from the state inventory in their 1995 modeling effort to assess interstate NOX transport contributions to ozone nonattainment in downwind states. Therefore operation of Monroe would clearly disturb a prior assessment of environmental impact.

10 ADEC included HCCP in its 1999 inventory, accidentally omitted it in 2002, and then included it again in 2005.

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The MOA between the US Department of Interior/National Park Service (NPS), Department of Energy (DOE), GVEA, and AIDEA was based on thorough environmental assessments considering HCCP emissions. Neither the Cyprus nor Monroe plants underwent pre-construction review under NSR or PSD before restart. They shut down after years of commercial operation. On the other hand, GVEA and AIDEA did obtain a PSD permit before HCCP Unit 2 construction, and did so by committing to a large permanent SO2, PM, and NOX reductions from Healy Unit 1 such that combined permitted NOX and SO2 emissions from HCCP Unit 2 and Unit 1 were less than Unit 1’s alone. Unlike Monroe and Cyprus, there is little to be gained by putting HCCP Unit 2 through PSD a second time before achieving commercial operation. Because it has gone through PSD, it has already demonstrated compliance with ambient standards, increments and air quality related values (AQRVs) applicable at the time of initial construction. HCCP Unit 2 is already built with innovative technology low NOX burners, sorbent injection acid gas control system, and a high efficiency fabric filter. The Healy Clean Coal Project was funded and is intended to implement technology that would serve as a model for a lower emitting coal plant. ADEC believes that the timing of the HCCP Unit 2 commercial startup is due to favorable market conditions. ADEC received numerous comments supporting the commercial startup in order to keep electric rates reasonable. These comments referred to the otherwise high electric rates due to the higher price of fossil fuel generated power. The preamble noted that the Clean Air Act provisions on PSD permit requirements emphasized ‘construction’ activities rather than, presumably, operation of a source. ADEC concludes that AIDEA always intended HCCP Unit 2 to achieve commercial operation, and that favorable market conditions will help to determine when that would occur.

Other criteria considered in the Monroe decision included that the Monroe plant was in an "'unmanned' condition", and that Monroe needed other permits before resuming operation. Trained operators provide 24-hour coverage of HCCP Unit 2. Unlike, the Monroe and Cyprus plants, HCCP Unit 2 does not need other permits in addition to air permits.

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c. ADEC Conclusions Regarding Changes in the Method of Operation

ADEC concludes that bringing HCCP into commercial operation does not fall under EPA's reactivation policy because there was never an intent by the owner and operator to permanently shut down the unit coupled the owner and operator’s actions to maintain the Unit in ready maintenance conditions. ADEC found that following the appropriate Federal Register language as guidance, and considering the differences between HCCP and the Monroe and Cyprus Casa Grande decisions, HCCP qualifies for the "hours of operation" exemption. Therefore, ADEC concludes that operation of HCCP does not constitute an action that should be compared against the PSD significance levels as a change in the method of operations.

4. Major modification and Significant Net Emissions Increase Calculations

Notwithstanding the arguments that the owner, the operator and ADEC have put forward to demonstrate the entirety of the HCCP commercial startup is not a modification, ADEC chose to demonstrate that the affiliated emissions increase of each regulated air pollutant is not PSD significant. ADEC concludes that HCCP Unit 2 emissions increases are not significant; therefore, commercial startup is not subject to PSD.

a. Test for an Existing Emissions Unit

40 C.F.R. 52.21(a)(2)(c) provides the PSD applicability test for changes to existing emission units:

A significant emissions increase of a regulated NSR pollutant is projected to occur if the sum of the difference between the projected actual emissions (as defined in [40 C.F.R. 52.21(b)(41)]) and the baseline actual emissions (as defined in [40 C.F.R. 52.21 (b)(48)(i) and (ii]), for each existing emissions unit, equals or exceeds the significant amount for that pollutant (as defined in [40 C.F.R. 52.21(b)(23)]).

HCCP is an emissions unit as defined under AS 46.14.990(11) and 40 CFR 51.166(b)(7), because it has the potential to emit a regulated NSR pollutant. The PSD provisions distinguish between two types of emissions units: A new unit is defined below. Any other emissions unit would be an existing emissions unit.

A new emissions unit is any emissions unit that is (or will be) newly constructed and that has existed for less than 2 years from the date such emissions unit first operated [40 C.F.R. 52.21(b)(7)(i)]

In the Department’s August 2010 draft final response to comments and permit decision submitted to EPA Region X for EPA’s non-objection, the Department asserted that HCCP meets the definition of a new emissions unit because it had not begun its commercial operations and that commercial operations are synonymous with “first

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operations.” EPA Region X staff verbally objected to this portrayal because the operator had fired the boiler, generated electricity and sold HCCP generated electric power in 1998 and in 1990. In consideration of EPA’s objections, the Department concedes it as more defensible to put forward a PSD applicability decision based upon existing emissions unit tests. At the time of this permit decision, HCCP would be an existing emissions unit by virtue of existing for more than 2 years from the date it first operated irrespective of if it achieved normal or commercial operation.

b. Selection of the Time Period for Baseline Actual Emissions

For any existing electric utility steam generating unit, baseline actual emissions means the average rate, in tons per year, at which the unit actually emitted the pollutant during any consecutive 24-month period selected by the owner or operator within the 5-year period immediately preceding when the owner or operator begins actual construction of the project. The Administrator shall allow the use of a different time period upon a determination that it is more representative of normal source operation. (emphasis added) [40 C.F.R. 52.21(b)(48)(i)]

Under 18 AAC 50.306(b)(1)(A) and 18 AAC 50.990(28), for the purposes of 40 C.F.R. 52.21(b)(48)(i), “administrator” means the Alaska Department of Environmental Conservation. As EPA has approved the state program as part of the State Implementation Plan under the federal Clean Air Act, this is also true under federal law. HCCP is an electric utility steam generating unit [40 C.F.R. 52.21(b)(31)] because it was constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. ADEC is using its authority under the above citations to find that the last five years do not represent normal operation. Since the first two years of operation were the only years in which HCCP Unit 2 operated, they are more representative of normal operation than no operation at all, based on the stated intent of both owner and operator to generate power with this Unit. ADEC is electing to choose time from this earlier two year period based upon unique HCCP Unit 2 circumstances – the delays to commence commercial operations due to the difficulty of the negotiations between the owner and intended operator. These circumstances are not comparable to any other case for which EPA has formulated guidance on choosing an alternative baseline period. ADEC considered two existing emissions unit interpretations for calculating the change in project emissions. Although ADEC further refined the time period from the first two year of operation and elected the latter of the two interpretations, ADEC presents both interpretations for full disclosure of its deliberations.

c. Potential to Emit as Baseline Actual Emissions (BAE) A variant of the potential to emit as BAE was put forward after EPA X requested withdrawal of the August 2010 draft final packet. The HCCP Unit 2 operations were

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startup and troubleshooting from January 1998 until August 1999, followed by a 90-day performance test from August through November 1999.

During the first two years, HCCP Unit 2 was still a new emissions unit because it remained in an experimental and start-up phase, and it still did not achieve the level of operation that was anticipated upon construction, or that was defined as commercial operation in the Owner and Operator’s November 6, 1991 Power Sales Agreement. Two years had yet to elapse from the date the unit first operated. During these start up and test periods, the actual emissions were less than anticipated for the unit’s normal operations in any two year period. During this time, HCCP Unit 2 still met the definition of a new emissions unit in 40 C.F.R. 52.21(b)(7)(i). As a new emissions unit, the following applies for baseline actual emissions.

For a new emissions unit, the baseline actual emissions for purposes of determining the emissions increase that will result from the initial construction and operation of such unit shall equal zero; and thereafter, for all other purposes, shall equal the unit's potential to emit (emphasis added)[40 C.F.R. 52.21(b)(48)(iii)].

Although HCCP Unit 2 is now an existing emission unit, it has been shut down since the first two years of operation. For this most representative time period the baseline actual emissions must be calculated as for a new emissions unit. Since initial startup happened at the beginning of the experimental phase and less than two years elapsed before November 1999 conclusion of the 90 day test period, baseline actual emissions are equal to its potential to emit.

This interpretation is especially appropriate for HCCP Unit 2 because the PSD rules for baseline actual emissions and projected actual emissions simply do not address the case where an existing emissions unit has gone through PSD, but has not yet any period of operations that represent normal operation. This scenario certainly fits under the phrase "all other purposes."

The only portions of the rule that specifically address an emissions unit that has not begun normal operation are in the definition of baseline actual emissions above for a new emissions unit as stated in 40 C.F.R. 52.21(b)(48)(iii), and in the definition of actual emissions in 40 C.F.R. 52.21(b)(21)(iii) and (iv). The latter paragraph (b)(21) citations authorized the use of potential to emit or source-specific allowable emissions respectively in place of actual emissions. 40 CFR 52.21(b)(21)(iv) was crafted specifically for the case where the emission unit has not begun normal operation. While the term “actual emissions” is no longer used in PSD to determine a significant emissions increase, for this situation it does serve as useful guidance.

For projected actual emissions (PAE), 40 C.F.R. 52.21(b)(41)(d) allows the use of potential to emit.

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Comparing HCCP Unit 2’s BAE to PAE, there is no emission increase. The PTE has not changed.

The two planned tasks for HCCP Unit 2 support emission units in Table B that might involve emission increases are considered by ADEC as routine maintenance, repair and replacement. As such any emission increase would not be creditable. As described in Item 2.b.i.1.c of this Appendix, the potential to emit is unchanged for the bucket elevator (equal to the 5 tpy enforceable limit), and the emissions factor for the clinker grinder is "not detectable." Therefore, the emission increase for HCCP could be up to five tpy from the bucket elevator, zero for all pollutants from the HCCP Unit 2 and zero tpy PM-10 from replacement clinker grinder.

PSD provisions call for the agency to account for contemporaneous emissions increases and decreases if emission increases are significant. Since emissions from HCCP commercial startup and all activities associated with startup are not significant, then the agency does not conduct a netting exercise.

After consideration of this “PTE as BAE” variant, the Department instead chose the following approach as a more suitable means to conclude the project does not trigger PSD.

d. BAE/PAE Test Based upon 90‐Day Test Period ADEC took the step to calculate BAE based upon the most representative selected operational period. ADEC then determined the difference between PAE and BAE based upon the methodology described below. The following findings are based on baseline actual and projected actual emission calculations.

i. Rationale for Selecting Another Time Period for Baseline Actual Emissions

As above, ADEC finds that the most recent five years are not representative of the intended normal commercial operation because the unit has not operated for the past five years.

Further, as noted above, the entire first two years of operation also deviate considerably from normal operation as a base-loaded electric steam generating unit. 40 C.F.R. 52.21(b)(48)(i), quoted above, allows the Administrator (ADEC) to choose another period that is more representative. That subsection does not restrict the alternative period to a two-year block. Therefore, ADEC selected the 90-day performance test period from August 1999 to November 1999 as the most representative operational period. Using an annual average or two year average would pull in operations during which there was significant down time associated with new unit start-up and experimental operations.

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Nothing in the BAE provision precludes ADEC from selecting a time period other than a one or two year period. Although one may claim that seasonal operational variability would call for a longer period than the 90 day test period, since AIDEA and GVEA intend to operate this emissions unit as a base loaded unit at or near its design capacity, seasonal variability should not be great enough to merit selecting a one to two year block as representing normal operations.

During this 90-day test period, HCCP Unit 2 achieved its most consistent and representative stable operation to date.

Table A shows ADEC's calculated emission rate for baseline actual emissions, and GVEA's calculated emissions for projected actual emissions from HCCP Unit 2. ADEC approves of GVEA's methodology and calculations.

These results show that emissions increase from commercial operation of HCCP will not result in a significant increase of a regulated NSR pollutant.

ii. BAE and PAE Calculations and Methodologies

Operational and emissions data for the test period came from spreadsheets provided by GVEA to ADEC staff in 2004. Input information included coal usage, Btu content, hours of operation, continuous emission monitor rolling average emission rates, average power provided to the grid, and coal sulfur content, all provided daily. ADEC determined emission factors from this GVEA data to calculate BAE. PAEs for all pollutants except SO2 are projected for HCCP using these same emission factors. For more detail, see the discussion below.

1. NOX

The emission factor of 0.277 lb NOX/MMBtu was the greatest 30 day rolling emission rate average from the test period for the days with the highest activity rates11. This factor is slightly higher than the average emission rate of 0.2751 lb NOX/MMBtu for all days of the 90 day period. This conservative approach overestimates the emissions increase because both BAE and PAE would be greater than had ADEC used the lower emission factor.

2. CO

The emission factor used for CO was taken from the May 19, 2004 ADEC Document, Potential to Emit Emission Assessment - HCCP Project, by Albert Faure. There was no acceptable emission test data discovered to determine an emission factor. The report based the emission factor upon one quarter of TRW's design goal of 200 ppm. ADEC also corrected a minor error in the 2004 document regarding EPA Method 19 emission rate calculations.

11 At or above 51.3 MW 24-hr average supplied to the grid, or about 95% highest expected operation.

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To compare with the selected emission factor, ADEC also used AP-42 Table 1.1-3 emission factor for subbituminous pulverized coal. The AP-42 emission factor is lower than the selected emission factor.

Using one quarter of the TRW design value as an emission factor is more conservative and predicts a greater emissions increase than AP-42 when ADEC compares BAE to PAE.

3. SO2

The GVEA-provided spreadsheets gave the highest 3-hour SO2 emission rate in lb/MMBtu for each day of the test period. ADEC used the average of these values for the test period to calculate BAE.

GVEA calculated the average control efficiency for the test period using the SO2 data, the fuel quantity and sulfur content. GVEA then calculated PAE emissions assuming no change of average control efficiency, and using both the average fuel sulfur for the test period12, and the highest annual average fuel sulfur found for Unit 1.13

The change in fuel quality (coal sulfur content) from the test period to the present coal is excludable from the BAE to PAE emissions increase test because the fuel property changes are unrelated to HCCP Unit 2 start-up, do not exceed an applicable enforceable limitation, and HCCP Unit 2 can presently accommodate the greater coal sulfur content.

4. PM‐10

The PM-10 emission factor was taken from a March 1999 source test report.

PM-10 calculations did not include any increase from tasks E.2 and H.1 because these are separate support emission units. As stated above, EPA's emission factor for H.1 is non-detect, so any increase would be negligible. E.2 is not quantifiable; the vibrator would only be used when the coal is wet and sticky and unlikely to cause airborne dust; and any emissions would be fed to a baghouse with an enforceable limit of 5 tpy. Therefore, when added to the HCCP Unit 2 calculated increase of 0.5 tpy (given in Table A), the maximum possible increase of 5.5 tons per year does not approach the project combined significance threshold of 15 tpy.

12 0.167 % sulfur. 13 From notes in GVEA's PAE calculation spreadsheet, March 10, 2011: 0.22% sulfur is highest annual average sulfur experienced for Unit 1 (2004).

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5. VOC

ADEC found no site-specific VOC emissions data for Unit 2. ADEC, then selected the VOC emission factor from AP-42 Table 1.1-19 for total non-methan organic compounds, (TNMOC) for pulverized coal. Although TNMOC does not have a one-to-one correlation to VOC as defined, TNMOC contains organic compounds that are excluded by definition from VOC. As such TNMOC emission factor is more conservative than that expressed for VOC. The TNMOC will predict a greater emissions change than a VOC emission factor.

6. Lead

ADEC calculated the BAE for lead using AP-42 emission factors because the 2004 document has no supporting emissions data specific to HCCP Unit 2. GVEA did not calculate the PAE, but the BAE is only 12% of the significance threshold, so the increase would not approach the significance threshold for this pollutant.

7. Greenhouse Gases

On June 3, 2010, U.S. EPA promulgated the Greenhouse Gas tailoring regulations requiring PSD review for greenhouse gases (GHG). From January 2, 2011, GHG PSD review does not apply to an existing major source modification unless the modification also triggers PSD review for another regulated PSD pollutant. On or after July 1, 2011, the GHG applicability threshold for an existing GHG major source modification will also include 75,000 tons of CO2 equivalence (CO2e) irrespective of PSD applicability for another regulated PSD pollutants. Because of this, the Department analyzed the project PSD permit applicability for greenhouse gases. The Department calculated the daily coal consumption rate for the HCCP BAE at 41.1 tons per hour. GVEA projected the coal consumption rate for HCCP at 45.1 tons per hour. The change in annual coal consumption is 34,465 tons per year of sub-bituminous coal. Applying emission factors for CO2 for Usibelli Coal and pulverized coal boiler methane and N2O emission factors for CO2e, the Department calculated a net emissions increase of 53,474 tons of CO2e per year. Assumptions: The U.S. Energy Information Administration emission factor is 214 lbs CO2 per MMBtu ( Energy Information Administration, Quarterly Coal Report, January-April 1994, DOE/EIA-0121(94/Q1) Washington, DC, August 1994), pp. 1-8.). For N2O and methane, the AP-42 emission factors for a wall-fired dry bottom pulverized coal boiler are 0.03 lb/ton and 0.04 lb.ton respectively of coal fired (AP-42 Table 1.1-19, 9/1998). The CO2e factor for N2O is 310 (a pound of N2O is equivalent to 310 pounds of CO2. The CO2e factor for methane is 21. The projected heat content is 7,200 Btu/lb for Usibelli coal.

The Department concluded that if GVEA begins actual construction of the project on or after July 1, 2011, the increase still would not approach the controlling 75,000 ton per year CO2e PSD modification threshold.

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Table A HCCP Emissions

BAE based on 90-day test period

PAE based on annual activity at 95% full capacity and same emission factors

NOx CO CO - AP42

SO2 PM-10 VOC

(TNMOC)PAE (fuel S =0.22%) 748.3 116.3 93.8

211 12.7 11.3

(fuel S =0.1668%)

160

Excludable amt.

51

BAE 717.3 111.5 90.1 154 12.2 10.8

Increase 31.0 4.8 3.7 6 0.5 0.4

iii. Effect of Other Assumptions for Emission Factors

1. NOX

Using the higher emission factor referenced under ii.1 above for PAE, and the lower emission factor for BAE, gives a worst case increase of 35.9 TPY, which is still lower than the significance threshold.14

2. CO

The worst possible case CO emission factor identified would be the TRW contract requirement design goal of 200 ppm. If used for both PAE and BAE, the resulting emission increase would be 4 x 4.8 = 19.2 tpy, which is still much less that the 100 tpy threshold.

iv. Exclusions from the projected actual emissions

The definition of projected actual emissions includes the following:

…the owner or operator of the major stationary source: (c) Shall exclude, in calculating any increase in emissions that results from the particular project, that portion of the unit's emissions following the project that an existing unit could have accommodated during the consecutive 24-month period used to establish the baseline actual emissions under paragraph (b)(48) of this section and that are also unrelated to the particular project, including any increased utilization due to product demand growth; [40 C.F.R. 52.21(b)(41)(ii)(c)]

14 This approach was not used because the lower factor could underestimate the BAE.

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ADEC considered two exclusions for HCCP Unit 2: that related to fuel sulfur, and that based upon future load demand.

1. Fuel Sulfur

The SO2 PAE was calculated assuming a fuel sulfur content of 0.22%, based on the highest annual average during the past ten years experienced for Unit 1. The BAE was calculated based on the actual average sulfur content during the 90-day test period of 0.167%. PAE presumes the same control efficiency as occurred during the BAE period.

ADEC finds that the emission increase from the increase in fuel sulfur is excludable under 40 C.F.R. 52.21(b)(41)(ii)(c), because the greater sulfur fuel could have been accommodated during the baseline period, and the greater fuel sulfur is not prohibited by an applicable enforceable requirement. As far as ADEC is aware, the coal seam (and its corresponding sulfur content) from which Usibelli mines and sells to GVEA is not dependent on HCCP commercial startup, as long as the Btu content is great enough to meet the needs of Unit 2.

2. Load Demand Growth

As part of their PAE submittal, GVEA described expected future load as follows:

Plant is expected to operate at about a 70% capacity factor (based on 55.5MW net demonstrated in September 1998) the first year after startup, and as unit is optimized and system load demand increases, is expected to operate at 90% – 95% capacity factor in the future. For this projection, a capacity factor of 95% was used.

GVEA has stated that at least part of the projected increase in HCCP's utilization after the first year of operation will result from optimizing the unit. Since optimization is related to commercial operations ADEC concluded load demand growth is not excludable under 40 C.F.R. 52.21(b)(41)(ii)(c). ADEC recognizes that additional utilization rates within the next five years might not to come from demand growth, but from a company decision to shift load to coal fired units when coal power is cheaper to produce. This is an expected part of the business plan for commercial startup. (That expected price difference is an essential factor in ADEC determining that the hours of operation exclusion applies.) Since the business decision would be based upon future relative price differential between coal generated power, oil generated power and power purchased from other generators connected or inter-tied with GVEA’s distribution grid system, it is not quantifiable as a projection. Further, GVEA explained that any increase in parasitic load would not result in an increase in utilization (and associated emission increase) because HCCP was

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viewed as supplying base load, and when operating would be at full capacity15. A change in parasitic load would only change the amount available for sale. This implies that other GVEA plants would supply the load that varies with demand.

Therefore, ADEC finds that, for the purposes of this PSD applicability determination, increase in HCCP utilization is not exempted under 40 C.F.R. 52.21(b)(41)(ii)(c). However, ADEC also concluded that once creditable exemptions are applied for coal sulfur variability, all pollutant emission increases are less than the significance thresholds.

ADEC presumes that unless GVEA can demonstrate that any utilization increase is due to a system wide demand growth rather than shifting load from other power plants to the Healy Power Plant and HCCP Unit 2, a similar finding would apply relative to the five years of monitoring and reporting that would be required under 40 C.F.R. 52.21(r)(6)(iii) and (iv).

ADEC further expects that, as long as GVEA's projected actual emission calculations are accurate, this should not present any operational problems, as the greatest emission increase shown in Table A is 31 tpy for NOX when PAE emission calculations were based on a 95% utilization factor.

e. Conclusions from Calculations

By either methodology, project emission increases are less than significance thresholds for all pollutants. Assuming applicability of the calculations using the 90-days test period, GVEA determined it will need to comply with the recording and reporting requirements for future actual NOX emissions, consistent with 40 C.F.R. 52.21(r)(6), because the calculated increase is greater than 50% of the significance threshold [40 C.F.R. 52.21(r)(6)(vi)(a)]. To comply with other permit conditions (notably, ton per year caps, emission fee terms, and emission inventory terms) GVEA will need to keep records of annual emissions of other pollutants. Such records must show that emissions for each pollutant must be less than the baseline actual emissions plus the significance thresholds. While increased SO2 emissions due to greater fuel sulfur is exempt, increases for any pollutant due to increased load are not, unless GVEA can demonstrate to ADEC that the increases are due to system wide demand growth, rather than shifting load from other GVEA power plants.

15 Teleconference between Kristen Dubois and Flint Campbell, GVEA, and Bill Walker, Blue Creek Consulting, a contractor for ADEC. Three teleconferences were held at ADEC's request, May 17, 20, and 21, 2010 for obtaining additional information allowing ADEC to evaluate the tasks listed in Table B -Table D.

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5. ADEC Findings Regarding PSD Applicability

Physical Changes

ADEC considers the tasks listed in Table B and Table C to be routine maintenance replacement or repair, or not to be changes to pollutant emitting activities. Whether all of the tasks are considered to be physical changes for evaluation as a potential major modification, or just those in Table D, any emission increase resulting from physical changes are not large enough to be quantified, and are less than the significance thresholds even when added to the emissions increases of HCCP. Changes in the Method of Operation

Following the evaluation of Section 3.a above, ADEC concludes that EPA's reactivation policy does not apply to HCCP commercial operations. Due to the differences between HCCP and other EPA precedents, as described above, ADEC concludes that

the 'hours of operation' exemption does apply to beginning commercial operation of HCCP; therefore, beginning HCCP commercial operation does not warrant further evaluation as a change in the method of operation that could be a major modification; and

even if that exemption did not apply, HCCP's unique circumstances, make appropriate ADEC's choice of alternative time periods as the most representative of baseline actual emissions.

ADEC further concludes that HCCP commercial startup is not a change in the method of operations.

BAE/PAE Calculations

Since some of the planned tasks are physical changes, and in the event an adjudicatory decision rules that commercial HCCP start-up is a change in the method of operations, the next step for PSD applicability would be to calculate emission increases from affected emissions units related to beginning commercial HCCP operation. By ADEC’s approach listed in Section 5d, the project does not cause a significant increase of a regulated NSR pollutant, even when the worst possible case emissions from physical changes are considered.

Therefore, ADEC concludes that HCCP is not subject to PSD review.

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6. Task Lists

Shaded cells in Table B - Table D highlight reasons why a task would not contribute to an increase in actual emissions.

Table B Tasks that are Routine

Task No.

Task Description RMR&R?

Emission Increase?

No change to

emitting activities?

Comments

A.1 Operating system replacement- Human machine interface.

Y N GVEA’s provider estimates that human machine interfaces are now replaced typically every 10 – 12 years. The HMI for Unit 1 has changed twice. With the current systems now digital, the likelihood is more frequent replacement than in the past. HCCP’s existing interface is no longer supported by the provider.

B.1 CEMS - Evaluate need to replace/ refurbish instruments; sample conditioning equipment, analyzers.

Y N This is unavoidable periodically for any CEMS.

C.1 Water Treatment: Replace reverse osmosis membranes. Inspect, reload multi-media filters.

Y N Unavoidable periodic tasks.

C.2 Water Treatment: Refurbish and reload demineralizer beds or replace with electro deionization (EDI) units.


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Task No.


Emission Increase?

No change to


Comments

C.3 Water Treatment: Replace water treatment programmable logic controllers (PLCs) human/machine interfaces (HMI).

Y N Not associated with any possible increase, including debottlenecking. Periodic upgrades to control system from dated technology is prudent management and should be routine.

C.4 Water Treatment: Refurbish/ replace water sampling instruments and analyzers.

Y N Not associated with any possible increase, including debottlenecking. Periodic technology upgrade is prudent management and should be routine.

D.1 Computer Control System: Review of burner management logic and software.

Y N Some of the other tasks are to repair damage caused by a coal dust fire/explosion. Coal fires and explosions are not uncommon in the industry. So resulting repairs are routine. This task is a part of that response – evaluation to prevent recurrence – and therefore also routine. The purpose of the burner management logic is to review operator inputs to prevent mistakes. GVEA’s believes that the explosion could have been prevented by more appropriate burner management logic. The task is not related to any emission increase. The burner management logic is not for regulating flame characteristics, but to avoid mistakes that could lead to a coal fire or explosion.

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Task No.


Emission Increase?

No change to


Comments

D.4 Upgrade Current PLC Communications from Data-Highway Plus to Ethernet: This task allows the new Distributed Control System (DCS) Human Machine Interfaces (HMIs) described in Task A.1 to communicate with Programmable Logic Controllers (PLCs). PLCs are devices that control event or batch sequencing processes for Unit 1 and HCCP subsystems (water treatment, ash handling, sorbent handling systems, etc). The PLCs will not change. The existing communication link is usable but cumbersome when connecting multiple HMIs.

Y N Could be considered part of the infrequent but periodic change associated with Task A.1. No effect on emissions because the PLCs will not change. Not essential for HCCP restart because the existing system, while reported to be cumbersome at times, is usable.

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Task No.


Emission Increase?

No change to


Comments

E.2 Add Vibrator to Bucket Elevator; Widen Chute. The vibrator would be programmed to give individual raps to loosen material when coal is wet and sticky. It is not a constant shaker. It would be used only when needed, not when coal is dry and could generate dust. Inlet and outlet are vented to baghouse.

Y Conditional

The vibrator mechanism is a one time addition to the bucket elevator emission unit. But efforts to keep material handling systems running smoothly at coal fired power plant must be routine. As with all tasks, at $40,500 fits easily within what GVEA reports as their projected annual maintenance budget. Would have no emission increase if only used when coal is wet or icy. An enforceable limit of 5 tpy PM applies to the elevator baghouse. The maximum increase in actual PM emissions must therefore be less than the total. Because the enforceable limit remains unchanged, there is no change in this emission unit’s potential to emit. This is a safety issue as saves manual cleanout, which might occur with buckets running. Any reduced down time, would not be debottlenecking because such down time was not used in calculations of PTE. Not essential to restart because unit can be run with manual cleanout of bucket elevator plugging.

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Task No.


Emission Increase?

No change to


Comments

E.3 Extend coal dust screw conveyor from Silo A to Silo B.

Y N One time extension of this conveyor, but additions or changes to material handling system routing is routine to the industry. After change, dust will discharge at either Silo A or B with no intermediate transfer points, so there will be no increase in particulate emissions.

F.1a Coal Feeder System: Pulverizer inspection, rebuild.


F1b, F1c, F2b, F3a

Inspection/ Repairs following coal dust explosion – air duct, tiles in coal transport tubes, coal feeder system, splitter/ cyclone tiles

Y N Unfortunately, coal fires/explosions are not uncommon in the industry. Though costly, repair after such events is essentially routine.

F2a Mill Exhauster Fan Replacement.

Y N This is, and will continue to be, an unavoidable periodic task. By upgrading to more corrosion/abrasion resistant material, GVEA will decrease the frequency of the task and reduce costs. The task will not prolong the life of the HCCP emission unit.

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Task No.


Emission Increase?

No change to


Comments

F1b, F1c, F2b, F3a, F4a, G1a, G1b, G1c, G2a, G2b, G3b I1,

Tasks that are clearly routine in the operation of a power plant: inspection, repair, replacement of worn or damaged parts or equipment: - Replace worn air nozzles; - General boiler inspection / cleaning; - Weld repairs – seal superheater pendent penetrations; - Inspect and clean boiler pendants; - Inspect and clean boiler generating tubes; - Tighten flange bolts on feedwater piping; - Inspect and repack boiler valves; - - Inspect induced draft fan, and evaluate need for new liners;

Y N

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Task No.


Emission Increase?

No change to


Comments

I2, L3, L4, L5, P1, Q2, Q3,

Clearly routine tasks cont’d: - Stack inspection and repair; - Condenser inspection and cleaning; - Condensate pump inspection/ repair as necessary; - Feedwater heater and deaerator inspection/ repair as necessary; - Rewind High Pressure Combustor Circulation Pump Motor; - Baghouse inspection; - Bag inspection - investigate bag condition, materials, and costs - if different bags selected for replacement, evaluate support structure;

Y N

Q5, AB1, AB2, AI1, AR1

Clearly routine tasks cont’d: - Replace SO2 process monitor / probe at SDA inlet; - Empty / Inspect Circulating Water pit (includes fire, screens, service water pits); - Inspect circulating water pump/ repair as appropriate; - Forced draft fan inspection for wear and corrosion; - Inspect boiler feed pump/ repair as appropriate.

Y N

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Task No.


Emission Increase?

No change to


Comments

F.4b

Combustor flame scanners - improve air purge flow. This task came from a comment by an engineering firm. The first part of GVEA’s task is to evaluate whether they should make the suggested adjustments.

Y N Flame scanners show whether there is flame present at their locations, and are a necessary safety feature. Purge air aimed at the scanners keeps them cool enough to continue to function. Even so, they need to be replaced at about six year intervals. The purge air is adjusted at the same interval after a scanner is replaced. This task is not essential to the restart. The scanners were functioning when HCCP was last run. If an increase in purge air flow is found to be beneficial, it would result in less frequent replacement of the scanners than would be needed otherwise.

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Task No.


Emission Increase?

No change to


Comments

F.4d Combustors - Evaluate need for additional combustion instrumentation. This task is part of the effort to achieve more efficient operation and would be part of the required ongoing effort to reduce emissions. The instrumentation to be evaluated would measure air flow, temperature, and pressure. The more accurately these parameters can be measured for input air streams, the easier it would be to provide the appropriate stoichiometric mixture.

Y N The evaluation is not a physical change or a change in the method of operation. If additional instrumentation is installed, it will have to be replaced periodically because of the abrasive quality of the coal. (GVEA intends to use a blend of run of mine and waste coal. The blend specifications will balance cheaper coal versus specific heat content and increased wear from abrasive lower quality coal.) Not related to any emission increase. Additional information will provide more data to better characterize performance of the combustion system. Addition of instrumentation, if done, is not essential to the restart, but could improve emissions and combustion efficiency.

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Task No.


Emission Increase?

No change to


Comments

G.2c Boiler: Convert natural circulation valves AC-to-DC power. Natural circulation valves are for a high pressure water circuit to cool the combustor when the system fails. The valves should be on battery power. If AC power is unavailable during an outage damage could result if the valves do not open to allow adequate cooling. This task would correct a design flaw.

Y N This task is of a type that would be routinely done when identified in any plant – one time design flaw correction to assure plant safety. If not done before restart, it would certainly be done using the plant maintenance budget at the first opportunity. Relative to RMR&R criteria:

Does not modify or replace major component.

Performed with plant in fully working order – unknown

Components on site – unknown

Not significant time to perform

Parts replacement, not parts addition – replacement of AC with DC components

Enhanced operation – no; prevention of maintenance problems

Frequency – once to correct design flaw.

Cost - $104K; well within projected annual maintenance budget.

Only emission related effect is to prevent possible damaging/emitting event.

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Task No.


Emission Increase?

No change to


Comments

H.1 Replace Slag Ash Grizzly with Clinker Grinder.

Y Possible One time change, but additions or changes to associated material handling systems is routine to the industry. Clinkers are wet when they would enter grinder. Detectable dust generation is not expected.

J.1, J.2, J.3

Steam Turbine and Generator: Inspection of steam turbine and generator - components/ clearances, relays, TWIP (turbine water induction protection).


K.1 Electrical System: Conduct protective relay settings check (engineering review & calibration check).

Y N Protective relays are used during run-up of large electrical motors (hundreds of hp.) Once up to speed the motors use much less energy. Relays shut off the current if run-up takes too long, to prevent overheating the motor. Settings drift and have to be periodically checked/reset.

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Task No.


Emission Increase?

No change to


Comments

K.2 Electrical System: Several plant electrical breakers may have been designed and/or installed with the wrong cable size. These cables will be confirmed suitable for service or replaced as necessary. This task comes from a Duke Energy Assessment that mentioned incorrect cable sizes but did not identify any. GVEA has not been able to locate the author to verify. No incorrect cable sizes have been identified to date, nor have any related problems occurred.

Y N Complying w/ electrical codes is routine. Only emission related change would be possible fire prevention.

L.6 Condensate System & Storage: Install check valve on combustor re-circulating line.

Y N Corrections/ changes in plumbing, such as adding valves, are routine to the industry.

M.1 Coal Silo Repairs. Y N Repair from coal fire. Such fires are not uncommon in the industry.

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Task No.


Emission Increase?

No change to


Comments

R.1 Bottom Ash Bucket Elevator plugging. Inspect and modify.

Y N Efforts to keep material handling systems running smoothly at coal fired (CF) power plant must be routine. As with all tasks, at $4,000 fits easily within what GVEA reports as their projected annual maintenance budget. Bottom ash is typically wet, which is what causes the plugging. Task is not essential to restart. The elevator runs intermittently. Manually unplugged during the interims.

R.2 Bottom Ash Conveyor – add heat traces.

Y N This project adds heat traces. Use of heat traces in cold environments is routine; traces will have to be replaced periodically. Possible minute increase in parasitic load.

U.1 Limestone Handling System – evaluate/replace with feeder control sys. w/ tighter operating range.

Y N If successful, this could be a once and done project. However, changes to material handling systems are routine at CF power plants. After the change the system is expected to feed limestone at more accurate rates. What is fed would better match what is intended – so the change would avoid wasting lime or feeding too little. An emission decrease would be expected for times that the existing system would under-feed limestone for acid gas controls. The system is adequate but could be improved, so it is not essential to restart.

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Task No.


Emission Increase?

No change to


Comments

Y.1 Water Treatment System: Repair tank linings on water and waste water storage tanks.

Y N Periodic task. The life of the liner depends on its contents. Replacing the liner is repainting with an epoxy based material.

AE.1 Fire System & Pump: Remove silt buildup at firewater intake.


AE.2 Fire System & Pump: Test and inspect fire pump.


AE.3 Fire System & Pump: Flush Entire Firewater System.


AF.1 Feedwater System: Routine replacement of feedwater heater bypass stop valve.

Y N Corrections/ changes in plumbing, or replacing valves, are routine to the industry.

AN.1 Service & Instrument Air: Air Compressor designed for Unit 1 and HCCP - inspect and repair as necessary.


AS.5 Circulating Water System: Repair vacuum priming system, install control valve.

Y N Repairs/changes in plumbing, such as adding valves, is routine to industry.

AU.1 Repair Steam Inerting & Instrumentation: Add steam trap at control valve (2AS-FV38A).

Y N Repairs/changes in plumbing is routine to the industry.

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Task No.


Emission Increase?

No change to


Comments

AU.2 Repair Steam Inerting & Instrumentation: Suction strainer inspection - Consultants have recommended a suction strainer remain on the boiler feed pump inlet at all times while in operation, not just at plant start up. Investigate.

Y N Corrections/changes in plumbing are routine to the industry.

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Table C Tasks that are Not Modifications for Other Reasons

Task No. Task Description

RMR&R?

Emission Increase?

No change to

emitting activities? Comments

F.9 Fluid Dynamics Modeling.

N N/A Y Modeling is not a physical or operational change. It is reportedly being done following GVEA’s responsibility under the MOA to continue to seek ways to reduce emissions. If the modeling results suggest changes that could involve increase in any pollutant (emission tradeoffs) GVEA will contact the ADEC before taking any further action.

AG.3 Coal Pile Management. N/A N/A N Task is to use coal pile management differently from what is in current use with only Unit 1, but that was already permitted, and used during previous HCCP operation.

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RMR&R?

Emission Increase?

No change to


F4e - F8, G4, Q4, Q6, AH1, AL1

Multiple Locations: Access improvement; stairs, platform, walkway, reroute pipe for door and panel access, camera position. These tasks involve cost trade offs. For hard to reach equipment that will need periodic maintenance, GVEA is evaluating the cost of putting up temporary scaffolding v. permanent access. Factors include cost of permanent access, frequency of maintenance, time lost in erecting temporary access, and safety.

Y N Y Improving efficiency of plant space could be considered routine. Does not increase any emission. Any down time that would be saved has not been used to reduce calculations of actual or potential emissions. Changes to access platforms, stairs, etc., are not physical changes to pollutant emitting activities. None of the changes are essential to the restart, because all of the locations can be reached for maintenance with effort.

N.1 Furnace Water Lance Platforms: Replace platforms. Water lances are high pressure water jets to clear out bottom ash. The access platform is being replaced to allow more space as a work safety issue.

Y N Y Improving efficiency of plant space could be considered routine. Changes to access platforms are not physical changes to pollutant emitting activities. Enlarging this access platform is not necessary for the restart, but will provide a safer workspace.

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RMR&R?

Emission Increase?

No change to


AC.1 HVAC Systems - Battery room ventilation: Task has been changed. Upon further investigation, there is proper ventilation. Several fan power switches are not readily visible, which will be corrected by new signage.

Y N Y Adequate labeling of equipment is routine. Adding labels is not a physical change to pollutant emitting activities.

AD.1 CO2 monitor: Install CO2 monitor in HCCP relay room. The room is served by a CO2 fire extinguishing system.

Y N Y This task should be considered routine because it is done solely for worker safety, is low in cost, and does not in any way increase emissions. Not a change to pollutant emitting activities. Estimated cost is $37K.

AP.1 Water Treatment System: Fix lab hood and ventilation - Reroute sample lines to eliminate obstruction opening the ventilation hood door and repair sample hood ventilation fan and ducting.

Y N Y Repairing needed equipment is a routine task. Rerouting lines to eliminate an obstruction is a non-routine one-time task, but one that has no associated air emissions, and is not a change to pollutant emitting activities.

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RMR&R?

Emission Increase?

No change to


AV.1 Tag & label all equipment, lines and valves for training and safety.

Y N Y Adequate labeling of equipment is routine, and is not a physical change to any system. Part of effort to make plant more efficient and to improve plant safety.

Doesn’t replace or modify major components

Could be done during full operation

Not enhance operation Performed once $80K

Not a physical change to pollutant emitting activities.

AQ.1 Waste Water Treatment System: Water supply intended for plant wash down hose bib contains dissolved solids and is not appropriate for human water supply. Either change water source or label as not potable.

Possibly

N Y Could be considered routine change for safety reasons. Task will not increase actual emissions. Not a physical change to pollutant emitting activities. The option is to label as non-potable.

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RMR&R?

Emission Increase?

No change to


AT.3 HVAC – Change Heat Balance. Relocate heaters.

N N Y Uncertain whether there will be iterations or once and done. Currently heater locations are inefficient. Example was given of one heater 35 feet above floor level. Heat will reach work level more easily without increase in energy used by relocation. Not a physical change to pollutant emitting activities. Not essential for restart. But worker comfort will be improved.

AT.4 HVAC Systems: Combined control rooms- office area HVAC improvements - Air pressure differences exist between the HCCP and Unit 1 causing potential safety concerns at doors between the two units. Investigate options to improve situation.

N N Y Possible minor change in parasitic load. Not a physical change to pollutant emitting activities. Not critical to plant functioning.

AT.5 HVAC Systems: Add exhaust fans to restrooms.

N N Y Possible minor change in parasitic load. Not a physical change to pollutant emitting activities. Not critical to plant functioning.

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RMR&R?

Emission Increase?

No change to


O.1 Emergency Lighting & Exit Signs: Convert emergency lighting and exit signs from DC to AC/UPS (uninterruptable power source).

N N Y Changes to lighting and signs are not physical changes to pollutant emitting activities. This task is not essential to the restart, but is a cost saving measure. The system could be left as DC power, but the change will retain the safety of dependable emergency lighting, without labor and replacement cost of routinely changing out batteries.

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Table D Efficiency Improvements

Project Compared to PSD Applicability Thresholds

These tasks are not modifications because they do not increase emissions and are not debottlenecking for (essential to) HCCP commercial startup. (See bold comments.)


RMR&R?

Emission Increase?

No change to


D.2 Computer Control System: Combine control rooms / combine loops.

N N Combining control rooms without changing control logic would not affect emission characteristics. The change is not essential to the restart. HCCP could be run with the separate control room. Combining control rooms would save money by allowing operation of both units with a smaller workforce.

D.3 Computer Control System: The current control logic has a significant amount of generic information that was disabled because it was not applicable to operating HCCP. This activity will remove the extraneous logic, which will allow for better operator understanding of plant function and easier trouble shooting of active logic loops.

N N Removing disabled logic would not affect emission characteristics. This task is not essential to the restart, but will make problem solving more efficient by removing non-essential code that would otherwise have to be waded through during problem solving efforts.

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RMR&R?

Emission Increase?

No change to


L.1 Add Second Condensate Storage Tank. Units 1 and 2 would have separate tanks. Unit 1 water would not have to meet more rigid Unit 2 specs.

N N Small increase in parasitic load. No direct emission impact. Not essential to restart but would save money. HCCP has more restrictive boiler water specifications. With one tank for both units, additional chemicals would have to be used to treat Unit 1 water that would not be needed if there were separate tanks.

V.1, W.1

Dry and Wet Ash Handling Systems.

N N Re-commissioning is not a periodic task. Running these systems was attempted as permitted by some entity other than GVEA during original HCCP testing. Reported to run poorly or not at all. GVEA will attempt to get the systems running properly. Pipes are totally enclosed and will not emit. Task is not for HCCP at all. Systems move Unit 1 ash to Unit 2 to avoid running redundant systems and because HCCP ash handling is better environmentally than the Unit 1 ash pond.

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RMR&R?

Emission Increase?

No change to


Y.2 Water Treatment System: Pre-reverse osmosis chemical treatment of plant water - relocate injection points for better mixing. The result of improved mixing for tasks Y.2 and Y.3 is that fewer chemicals would be used to achieve the desired water quality, and presumably, the potential for increased maintenance problems in the future caused by pockets of off spec water would be reduced.

Possible N Y.2 and Y.3 could be part of what will be ongoing routine efforts to make HCCP run more efficiently. The combined estimated cost for all four tasks is $94K. No air emission impacts are associated with Tasks Y.2, Y.3, Z.1, and Z.2, except that, if future scaling is reduced, future air emissions per unit of power produced would also be reduced. Not essential to restart. The boilers were run during the test phase as is without the efficiency improvements.

Y.3 Water Treatment System: Plant well water chlorination - relocate sodium hypochlorite injection point to improve mixing.

Possible N See discussion for Y.2 Not essential to restart. The boilers were run during the test phase as is without the efficiency improvements.

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RMR&R?

Emission Increase?

No change to


Z.1

Waste Water Treatment System: Install acid injection skid upstream of API separator - improve wastewater de-oiling. Neutralize drainage water prior to the oil separation process to improve de-oiling by lowering waste water pH. The current design routes off-spec waste water to the neutralization tank for treatment creating sub-optimal de-oiling of the waste water.

Possible N

See discussion for Y.2 No effect on air emissions Not essential for HCCP restart because the change is not necessary to meet water quality standards.

Z.2 Waste Water Treatment System: Relocate acid/caustic injection point and pH measurement location on neutralization tank for more effective mixing.

Possible N See discussion for Y.2 No effect on air emissions Not essential for HCCP restart because the change is not necessary to meet water quality standards.

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RMR&R?

Emission Increase?

No change to


AA.1 Boiler Water Chemistry: Install sample lines, instruments, analyzers to meet AVT recommendations. This task has been redefined to move the injection point for mono ethanol amine to a different existing port following an EPRI recommendation. GVEA describes the existing injection point as adequate but not optimal. The expected result would be better water quality and less chemical use.

Possible N Along with Y.2 and Y.3, could be viewed as ongoing routine efforts to improve plant efficiency. No effect on air emissions. Better water quality may result in better operating efficiency in the future. The task would not be essential to restart because the existing setup is adequate.

AA.2 Boiler Water Chemistry: Replace currently oversized chemical injection pumps /lines, and relocate injection points for better mixing based on EPRI recommendations. Purpose to improve pH control. The result would be the use of less power, and less chemical.

Possible N Once. Could be considered routine as part of efforts to make plant more efficient whenever such opportunities are identified. No effect on air emissions. Not essential to restart. The boilers were run during the test phase as is without the efficiency improvements.

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RMR&R?

Emission Increase?

No change to


AN.2 Add Second Compressor Tank for instrument air system and service air. Receiver tank fed by a number of compressors serving as an air day tank. This task is to reduce maintenance costs on the compressors feeding the receiver tank. With one receiver, tank draw down is more rapid and compressors cycle on and off more frequently. As with other equipment longer more infrequent run times cause less wear on the compressors than frequent starts and stops.

N N One time addition of new equipment. If task decreases down time, it would not be an increase in PTE because such down time was not accounted for in the PTE calculations. There is no other air emission effect. Not essential to restart because the existing compressor tank has enough capacity to serve both Units 1 and 2.

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7. Chronology of Events

Table E Chronology of Events

The following is the chronology of events related to the HCCP as explained by GVEA in its letter to ADEC dated May 26, 2009. Some of these incidents have not been independently verified, but are presumed to be accurate. Those unverified statements are noted as such below.December 1991 AIDEA and GVEA enter into a Power Sales Agreement (PSA), under

which GVEA agrees to be operator of HCCP and to purchase all power from HCCP for 35 years once the plant achieves “commercial operations”. The PSA required a 90 day reliability test before January 1, 2000.

March 10, 1993 ADEC issues PSD Air Quality Control (AQC) Permit-to-Operate 9231-AA007. In this permit, ADEC determines that HCCP�s entrained combustion system is Best Available Control Technology (BACT) for Oxides of Nitrogen (NOX) and installed Sulfur Dioxide (SO2) controls were BACT for SO2 for the HCCP.

May 12, 1994 ADEC issues revised PSD AQC Permit-to-Operate 9431-AA001, which incorporates conditions of a Memorandum of Agreement (MOA) with US Department of Interior/National Park Service (NPS), Department of Energy (DOE), GVEA, and AIDEA.

January 1998 GVEA commences operations of HCCP. The unit reached full load for the first time in March of 1998. [UNVERIFIED]

March 1998 In March of 1998, AIDEA notifies GVEA that it did not intend to conduct or evaluate 90-day performance testing of the HCCP in such a way as to meet all requirements of PSA (and other agreements between parties). [UNVERIFIED]

May 1998 GVEA files suit against AIDEA seeking a court declaration of what PSA contract requires. [UNVERIFIED]

August 17, 1999 HCCP operates for 90 consecutive days (ending on November 15, 1999). Late 1999 an independent engineering firm"s evaluation of 90-day performance test indicates exceedances of short term sulfur dioxide (SO2) emission limits and opacity requirements during startup, shutdown, and equipment repairs. The firm also concludes that HCCP had not met all criteria required to pass PSA‟s 90 day test for commercial operations.

December 30, 1999 GVEA notifies AIDEA of its intent to terminate the PSA at midnight on December 31, 1999.

March 8, 2000 May 1998 suit settled under a Settlement Agreement effective March 8, 2000. This Agreement provides for an Interim Shutdown Period during which the plant will be temporarily shutdown while GVEA considers full retrofit to conventional coal burning or a limited retrofit (improvement to clean coal technology). The agreement provided that the Shutdown Period would expire on the earlier of

GVEA�s election to proceed with Retrofit work; or GVEA�s election to abandon efforts to obtain authorization to

pursue Full Retrofit; or One year from the Turnover Date.

April 7, 2000 Interim Shutdown Period begins. [DATE UNVERIFIED.] GVEA begins discussion with ADEC to determine regulatory requirements for plant retrofit to more conventional technology. Discussions continued beyond expiration of one year period.

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September 10, 2001 GVEA requests an administrative amendment of the Title V permit to allow a retrofit of the HCCP to replace the clean coal technology with low NOX burners.

April 11, 2002 ADEC denies the request for the administrative changes (to the Title V permit) to allow a retrofit. ADEC “unable to conclude that the proposed retrofit technology constitutes “equivalent” equipment under the regulations.”

April 2, 2003 GVEA formally terminates the PSA in April 2003. April 2003 For a few months subsequent to PSA termination, GVEA continues to

explore the possibility of a full retrofit of the HCCP and suggests to AIDEA the possibility of purchase of HCCP. [UNVERIFIED]

June 28, 2004 AIDEA notifies ADEC that AIDEA intended to act to “preserve its ability transfer the HCCP from GVEA to AIDEA (or a third party) and to pursue the continued operation of the HCCP with a limited retrofit of the clean coal technology.”

June 2004 Subsequent to the June 28, 2004 letter, AIDEA and GVEA began negotiations for an amended ground lease to allow AIDEA to operate HCCP, as provided in the Settlement Agreement. [UNVERIFIED.]

November 2005 While negotiating with GVEA for an amended ground lease, AIDEA sued GVEA to seek a court order requiring a ground lease and other agreements allegedly necessary for it to operate the unit. [UNVERIFIED.]

March 2006 HCCP Condition Assessment and Restart Study – HCCP/Unit 1 Independent Operations report prepared by Shaw, Stone & Webster (SSW) indicates that in 1999 “GVEA was contracted to perform plant maintenance to maintain HCCP in a standby condition and to prevent significant system and equipment deterioration.” In the report, SSW concludes that

HCCP is in good condition and has incurred since 1999 no significant deterioration during the shutdown.

If recommendations for remediation and system separation are implemented, SSW knows of no reason why HCCP cannot be operated separately from Unit 1 in a safe and reliable manner for the duration of its design life provided industry standard operation and maintenance activities are performed.

The report includes a list of high priority tasks (required prior to restart) and low priority tasks (may occur prior to restart but can occur later if at all.)

January 16, 2009 After years of discovery and mediation, the November 2005 litigation is stayed by AIDEA and GVEA by mutual agreement in January 2009. Under a settlement, GVEA has agreed to purchase HCCP and now intends to operate it as permitted, without a retrofit.

May 26, 2009 GVEA submits a letter to ADEC requesting a determination by ADEC that PSD is not applicable to startup of the HCCP. In the letter, GVEA estimates that costs of $1.125 million to $1.275 million would be incurred in bringing the HCCP into operation. GVEA estimates that the work would require seven to ten months to complete. GVEA also provide considerably higher estimates for additional work to conduct routine maintenance, safety reviews, evaluations, updates, and any necessary repairs and maintenance.

Documents

AQ0173TVP02 Final Permit SOB 012712 - Sierra Club · AIR QUALITY OPERATING PERMIT ... Million standard cubic feet MR&R.....Monitoring, Recordkeeping, ... or equal to a nominal ten