Expiration Date: February 3, 2017

The Department of Environmental Conservation, under the authority of AS 46.14 and 18 AAC 50, issues an operating permit to the Permittee, Golden Valley Electric Association, Inc., for the operation ofthe Healy Power Plant.

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

As set out in AS 46.14.120(e), the Permittee shall comply with the terms and conditions ofthis

operating 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 of regulation 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

\\ab-svñgroups\AQ\Pcrmics\Awq-permits\Airfacs\OVEA\Hcaly\Opcraling\TVPO2. Rencwal\Final\AQO I 73TVP02 Final ramit SOB 012712 docx
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
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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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
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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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 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

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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
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

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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) 

1⁄4 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 visibleemissions 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 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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(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: 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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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. 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

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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. 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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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; 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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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. 

 
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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

 
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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] 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 7] 

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. 

17.4 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 4. Report in accordance with Condition 99 

whenever the gallons combusted in EU ID 4 exceed 672,978 gallons per calendar 

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

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 5] 

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. 

18.4 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 5. Report in accordance with Condition 99 

whenever the gallons combusted in EU ID 5 exceed 420,480 gallons 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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 56] 

21.1 Compliance shall consist of an annual certification, in accordance with Condition 

101, that the facility has met the requirements of Condition 21. 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 12] 

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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 48] 

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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 49] 

25.1 Compliance shall consist of an annual certification, in accordance with Condition 

101, that the facility has met the requirements of Condition 25. 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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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: 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 50] 

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 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

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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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 53] 

27.1 Compliance shall consist of an annual certification, in accordance with Condition 

101, that the facility has met the requirements of Condition 27. 

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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 54] 

28.1 Compliance shall consist of an annual certification, in accordance with Condition 

101, that the facility has met the requirements of Condition 28. 

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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 57] 

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. 
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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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Exhibit D] 

30.1 Compliance shall consist of an annual certification, in accordance with Condition 

101, that the facility has met the requirements of Condition 30. 

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. 
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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. 
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32. Permittee shall submit a Quality Assurance Plan to the Department for each continuous 

emission monitoring system, as described in Condition 30. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 17] 

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 50.040(j) and 18 AAC 50.326(j)] 

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

[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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 26] 

34.1 Compliance shall consist of an annual certification, in accordance with Condition 

101, that the facility has met the requirements of Condition 34. 

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. 

[18 AAC 50.040(j) and 18 AAC 50.326(j)] 

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

[AQC Permit #9431-AA001, Condition 27 and 

Construction Permit #9831-AC018, Condition 22] 

35.1 Compliance shall consist of an annual certification, in accordance with Condition 

101, that the facility has met the requirements of Condition 35. 

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. 
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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)] 
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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 50.040(j) and 18 AAC 50.326(j)] 

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

[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; 
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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. 
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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 zerojig 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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Healy Power Plant Expires: February 3, 2017 

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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

    



 







    



 





   R A

B S

R

R S

NM E

R A

S A B M E E

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. 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 60 of 74 

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. 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 61 of 74 

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. 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 62 of 74 

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 computerreadable 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: 

[18 AAC 50.040(j)(4) and 18 AAC 50.326(j)] 

[40 C.F.R. 71.6(a)(12)] 

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. 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 63 of 74 

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.

[18 AAC 50.040(j)(4) and 18 AAC 50.326(j)] 

[40 C.F.R. 71.6(a)(13)] 

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 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 64 of 74 

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)] 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 65 of 74 

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)] 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 66 of 74 

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)] 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 67 of 74 

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)] 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 68 of 74 

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. 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 69 of 74 

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 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 70 of 74 

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 

 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 71 of 74 

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] 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 72 of 74 

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
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 73 of 74 

(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 

 
Permit No. AQ0173TVP02 Issued: February 3, 2012 

Healy Power Plant Expires: February 3, 2017 

Page 74 of 74 

(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: DEC.AQ.Airreports@alaska.gov - 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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 3 of 38 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 4 of 38 

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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 5 of 38 

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)]. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 6 of 38 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 7 of 38 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 8 of 38 

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 

Permit No. 

AQ0173TVP02

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 

17 through 21 BACT and Owner 

Requested 

Emission Limits 

26 through 30 Same information 

 

4

 This table does not include all standard and general conditions. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 9 of 38 

Permit No. 

AQ0173TVP01, 

Revision 2 

Condition number 

Description of 

Requirement 

Permit No. 

AQ0173TVP02

Condition Number How Condition was revised 

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. 

23 through 28 BACT and Owner 

Requested 

Emission Limits 

32 through 37 Same information 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 10 of 38 

Permit No. 

AQ0173TVP01, 

Revision 2 

Condition number 

Description of 

Requirement 

Permit No. 

AQ0173TVP02

Condition Number How Condition was revised 

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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 11 of 38 

Permit No. 

AQ0173TVP01, 

Revision 2 

Condition number 

Description of 

Requirement 

Permit No. 

AQ0173TVP02

Condition Number How Condition was revised 

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 

60 through 63 Same information 

51 NSPS Subpart Y 64 Same information 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 12 of 38 

Permit No. 

AQ0173TVP01, 

Revision 2 

Condition number 

Description of 

Requirement 

Permit No. 

AQ0173TVP02

Condition Number How Condition was revised 

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 

11 through 13 Same information 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 13 of 38 

Permit No. 

AQ0173TVP01, 

Revision 2 

Condition number 

Description of 

Requirement 

Permit No. 

AQ0173TVP02

Condition Number How Condition was revised 

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% 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 14 of 38 

Permit No. 

AQ0173TVP01, 

Revision 2 

Condition number 

Description of 

Requirement 

Permit No. 

AQ0173TVP02

Condition Number How Condition was revised 

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 

74 through 77 Same information 

79 Open burning 84 Same information 

80 Air Pollution 

Prohibited 

78 Same information 

81 Technology based 

emission standard 

79 Same information 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 15 of 38 

Permit No. 

AQ0173TVP01, 

Revision 2 

Condition number 

Description of 

Requirement 

Permit No. 

AQ0173TVP02

Condition Number How Condition was revised 

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 

95 through 98 Same information 

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 

110 through 113 Same information 

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) 

 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 16 of 38 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 17 of 38 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 18 of 38 

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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 19 of 38 

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 sourcespecific 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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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-toOperate 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.) 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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 technologybased 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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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 stationarysource 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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 29 of 38 

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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

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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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 31 of 38 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 32 of 38 

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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 33 of 38 

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 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 34 of 38 

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 stationarysource 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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 35 of 38 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 36 of 38 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 37 of 38 

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. 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 38 of 38 

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 

Page 1 of 3 

APPENDIX A 

GVEA Permit Applicability Determination 

for Resuming Operation of the 

Healy Clean Coal Project (HCCP) 08-20-2009 

 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 2 of 3 

APPENDIX B 

Issue Statement: 

Does a Prevention of Significant Deterioration (PSD) Review 

Apply to the Restart of the HCCP? 

10-12-2009 

 
Statement of Basis February 3, 2012 

Permit No.AQ0173TVP02 

 Page 3 of 3 

APPENDIX C 
p

August 20, 2009

Kristen DuBois

Environmental Officer

Golden Valley Electric Assoc.P0 Box 71249

Fairbanks, AK 99707-1249

Subject: Permit Applicability Determination for resuming operation ofthe Healy Clean Coal

Project (HCCP)

Dear Ms. DuBois:

In your May 26, 2009 letter, you asked the Department to confirm GVEA’s conclusion that the

activities GVEA will conduct to bring HCCP out of warm lay-up to fully operational condition will

not trigger Prevention of Significant Deterioration (PSD) review. We have reviewed all theinformation you have submitted regarding these activities. Based on that information, as well as

applicable 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 not

trigger EPA’s reactivation policy. Therefore, we agree with your conclusion that no PSD permit is

required for these activities.

Although we reach the same conclusion, we may not agree with every point in the analysis that you

provided with your May 2009 letter. My staff is preparing a written technical analysis explaining

the basis of our conclusion, and we will include this analysis in the Statement of Basis for your

Title V permit. In the meantime, if you have any questions about this matter, please call me at 907-465-5103.

Sincerely,

ohn F Kuterbach

Air Permit Program Manager

Cc:

via email

Larry Hartig, CommissionerAlice Edwards, Director

Pat Nair, EPA Region 10

Nancy Helm, EPA Region 10

“Clean Air”
g

, 

9

03

2495
1 

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 
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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. 
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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. 
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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. 
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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 
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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”. 
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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 
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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. 
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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 rulemaking.) 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.
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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 
GVEA Healy Clean Coal Plant PSD Applicability Analysis 

October 12, 2009 

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 

   
Page 2 of 59

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
Page 3 of 59

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 
Page 4 of 59

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 
Page 5 of 59

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. 
Page 6 of 59

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.
Page 7 of 59

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 nonroutine 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. 
Page 8 of 59

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. 
Page 9 of 59

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 
Page 10 of 59

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 
Page 11 of 59

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 
Page 12 of 59

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. 
Page 13 of 59

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. 3

Letter 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 
Page 14 of 59

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. 
Page 15 of 59

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. 
Page 16 of 59

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 layup 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) 
Page 17 of 59

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. 9

Letter 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. 
Page 18 of 59

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.
Page 19 of 59

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. 

   
Page 20 of 59

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 
Page 21 of 59

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 
Page 22 of 59

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. 
Page 23 of 59

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. 
Page 24 of 59

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. 
Page 25 of 59

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). 
Page 26 of 59

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 wallfired 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.   
Page 27 of 59

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. 
Page 28 of 59

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 
Page 29 of 59

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. 
Page 30 of 59

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. 

   
Page 31 of 59

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 RM

R&

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. 

Y N Unavoidable periodic tasks. 
Page 32 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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. 
Page 33 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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. 
Page 34 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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 Conditiona

l 

 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. 
Page 35 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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. 

Y N Unavoidable periodic tasks. 

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. 
Page 36 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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 
Page 37 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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 
Page 38 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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. 
Page 39 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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. 
Page 40 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

Comments 

G.2c Boiler: Convert natural 

circulation valves AC-toDC 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. 
Page 41 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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). 

Y N Unavoidable periodic tasks. 

K.1 Electrical System: Conduct 

protective relay settings 

check (engineering review 

& calibration check). 

Y N Protective relays are used during runup 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. 
Page 42 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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. 
Page 43 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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 underfeed limestone for acid gas controls. 

The system is adequate but could be 

improved, so it is not essential to 

restart. 
Page 44 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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. 

Y N Unavoidable periodic tasks. 

AE.2 Fire System & Pump: Test 

and inspect fire pump. 

Y N Unavoidable periodic tasks. 

AE.3 Fire System & Pump: Flush 

Entire Firewater System. 

Y N Unavoidable periodic tasks. 

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. 

Y N Unavoidable periodic tasks. 

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 (2ASFV38A). 

Y N Repairs/changes in plumbing is 

routine to the industry. 
Page 45 of 59

Table B 

Tasks that are Routine 

Task 

No. 

Task Description RM

R&

R? 

Emission 

Increase?

No change 

to 

emitting 

activities? 

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. 

 
Page 46 of 59

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. 
Page 47 of 59

Table C 

Tasks that are Not Modifications for Other Reasons 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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.
Page 48 of 59

Table C 

Tasks that are Not Modifications for Other Reasons 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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. 
Page 49 of 59

Table C 

Tasks that are Not Modifications for Other Reasons 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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. 

Possib

ly 

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 nonpotable. 
Page 50 of 59

Table C 

Tasks that are Not Modifications for Other Reasons 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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.
Page 51 of 59

Table C 

Tasks that are Not Modifications for Other Reasons 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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.

 
Page 52 of 59

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.) 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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. 
Page 53 of 59

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.) 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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. 
Page 54 of 59

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.) 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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.
Page 55 of 59

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.) 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

Z.1 Waste Water Treatment 

System: Install acid 

injection skid upstream 

of API separator - 

improve wastewater deoiling. 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. 
Page 56 of 59

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.) 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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. 
Page 57 of 59

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.) 

Task 

No. Task Description 

RMR

&R? 

Emission 

Increase? 

No change 

to 

emitting 

activities? Comments 

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. 

   
Page 58 of 59

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 HCCPs 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 

 GVEAs election to proceed with Retrofit work; or 

 GVEAs 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. 
Page 59 of 59

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.