C:\Documents and Settings\pwright\Desktop\bpxampufinal\BPXA MPU FinalPermit&SOB-Revision1.doc 

DEPARTMENT OF ENVIRONMENTAL CONSERVATION 

AIR QUALITY CONTROL OPERATING PERMIT 

Permit No. 200TVP01 Issue Date: April 14, 2003 

Application No. 200 Expiration Date: May 13, 2008 

Revision 1: May 25, 2004 

The Department of Environmental Conservation, under the authority of AS 46.14 and 

18 AAC 50, issues an operating permit to the Permittee, BP Exploration (Alaska) Inc., for the 

operation of the Milne Point Production Facility. 

This permit satisfies the obligation of the 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(c), the Permittee shall comply with the terms and conditions of this 

operating permit. 

All stationary source-specific terms and conditions of Air Quality Control Construction Permit 

No. 0073-AC023 and 200CP02 have been incorporated into this Operating Permit. The 

reporting requirements in this Operating Permit also replace the reporting requirements of 

Exhibit D of Air Quality Control Permit-to-Operate No. 9673-AA005. 

This Operating Permit becomes effective May 14, 2003. 

John F. Kuterbach, Manager 

Air Permits Program 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 2 of 61 

Table of Contents 

List of Abbreviations Used in this Permit....................................................................................2 

Section 1. Identification................................................................................................................2 

Section 2. General Emission Information.....................................................................................2 

Section 3. Source Inventory and Description ...............................................................................2 

Section 4. Emission Fees ..............................................................................................................2 

Section 5. Source-Specific Requirements.....................................................................................2 

Fuel-Burning Equipment .............................................................................................................2 

Emission Units Subject to Federal New Source Performance Standards (NSPS), Subpart A ....2 

Storage Tanks Subject to NSPS Subpart Kb, Emission Unit ID(s) 19 and 20 ............................2 

Emission Units Subject to NSPS Subpart Dc, Emission Unit ID(s) 3 and 4...............................2 

Turbines Subject to NSPS Subpart GG NOX Standard, Emission Unit ID(s) 1 and 2 ..............2 

Emission unit Subject to Owner Requested Limit to Maintain the HAP-minor Status of the 

Facility .........................................................................................................................................2 

Emission units Subject to Owner Requested Limits for Ambient Air Quality Protection ..........2 

Heaters Subject to BACT Limits .................................................................................................2 

Turbines Subject to BACT and PSD Avoidance Limits..............................................................2 

Vents Subject to BACT Limits....................................................................................................2 

Fuel Consumption Monitoring.....................................................................................................2 

Hours of Operation Monitoring for Fuel-fired Emission units....................................................2 

Section 6. Visible Emissions and PM Monitoring, Recordkeeping and Reporting......................2 

Section 7. Stationary source-Wide Requirements ........................................................................2 

Section 8. Insignificant Sources....................................................................................................2 

Section 9. Generally Applicable Requirements............................................................................2 

Section 10. General Source testing and Monitoring Requirements................................................2 

Section 11. General Recordkeeping, Reporting, and Compliance Certification Requirements .....2 

Section 12. Standard Conditions Not Otherwise Included in the Permit........................................2 

Section 13. Permit As Shield from Inapplicable Requirements .....................................................2 

Section 14. Visible Emissions Forms .............................................................................................2 

Visible Emissions Field Data Sheet.............................................................................................2 

Visible Emissions Observation Record .......................................................................................2 

Section 15. SO2 Material Balance Calculation ...............................................................................2 

Section 16. ADEC Notification Form.............................................................................................2 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 3 of 61 

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 

BPXA...................BP Exploration (Alaska) Inc. 

BTU......................British Thermal Units 

CEMS...................Continuous Emissions Monitoring System 

CFP ......................Central Facilities Pad 

C.F.R....................Code of Federal Regulations 

CO........................Carbon Monoxide 

DAR .....................Data Analysis Report 

DLE......................Dry Low Emissions 

dscf.......................Dry standard cubic foot 

EEMSP.................Excess Emissions and Monitoring Systems Performance 

EPA......................US Environmental Protection Agency 

Gal........................gallons 

gr./dscf .................grain per dry standard cubic foot (1 pound = 7000 grains) 

GPA......................Gas Producers Association 

GPH......................gallons per hour 

HAPs or HACs.....Hazardous Air Pollutants or Hazardous Air Contaminants [HAPs or HACs

as contained in AS 46.14.990(14)] 

hp..........................horsepower 

hr ..........................hour 

ID .........................Source Identification Number 

kPa........................kiloPascals 

LHV .....................Lower Heating Value (or Net Heating Value) 

MACT..................Maximum Achievable Control Technology [MACT as contained in 

40 C.F.R. 63] 

MMBtu.................Million British Thermal Units 

MR&R..................Monitoring, Recordkeeping, and Reporting 

MW ......................megaWatts 

NAICS..................North American Industry Classification System 

NESHAPs ............Federal National Emission Standards for Hazardous Air Pollutants

[NESHAPS as contained in 40 C.F.R. 61] 

NOX......................Nitrogen Oxides 

NSPS....................Federal New Source Performance Standards [NSPS as contained in 

40 C.F.R. 60] 

O2 .........................Oxygen 

PEMS ...................Predictive Emissions Monitoring System 

pph........................pounds per hour 

ppm ......................Parts per million 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

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ppmv ....................Parts per million by volume 

ppmvd ..................Parts per million by volume dry 

PM-10 ..................Particulate Matter less than or equal to a nominal ten microns in diameter 

PS .........................Performance specification 

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

PTE ......................Potential to Emit 

RM .......................Reference Method 

SIC. ......................Standard Industrial Classification 

SO2 .......................Sulfur dioxide 

SSPOWGEN........Software program developed by General Electric Inc. 

TPH......................Tons per hour 

TPY......................Tons per year 

VOC .....................volatile organic compound [VOC as defined in 18 AAC 50.990(103)] 

wt% ......................weight percent 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

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Section 1. Identification 

Names and Addresses 

Permittee: BP Exploration (Alaska) Inc.

 900 East Benson Boulevard 

 Anchorage, AK 99508 

Facility Name: Milne Point Production Facility

 Central Facilities Pad (CFP), B-Pad, and E-Pad 

Location of CFP: 70° 27.5′ North; 149° 26.2′ West 

Physical Address: Milne Point Unit, North Slope, Alaska 

Owner: BP Exploration (Alaska) Inc. 

 900 East Benson Boulevard 

 Anchorage, Alaska 99508 

Operator: BP Exploration (Alaska) Inc. 

 900 East Benson Boulevard 

 Anchorage, Alaska 99508 

Permittee’s Responsible Official Edward D. Lafehr, Milne Point Delivery Manager 

Designated Agent: CT Corporation System 

 801 West 10th Street, Suite 300 

 Juneau, AK 99801 

Facility and Building Contact: Facilities Supervisor 

 (907) 670-3331 

 

Fee Contact: James A. Pfeiffer, Air Specialist 

 MB2-6, P.O. Box 196612 

 Anchorage, AK 99519-6612 

Stationary source Process Description 

SIC Code of the Facility: 1311 

NAICS Code of the Facility: 211111 

[18 AAC 50.350(b)(1), 1/18/97] 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

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Section 2. General Emission Information 

[18 AAC 50.350(b)(1), 1/18/97] 

Emissions of Regulated Air Contaminants, as provided in the Permittee's application: 

NOX, CO, SO2, PM, VOC, and various hazardous air pollutants (HAPs). 

Stationary source Classifications: 

(1) 18 AAC 50.300(b)(2) - Milne Point Production Facility is a stationary source containing 

fuel-burning equipment with a rated capacity of 100 million Btu (MMBtu) per hour or 

more 

(2) 18 AAC 50.300(c)(1) - (Prevention of Significant Deterioration (PSD) major facility) - 

Milne Point Production Facility is a stationary source that has the potential to emit (PTE) 

250 tons per year (TPY) or more of a regulated air pollutant in an area designated as in 

attainment or unclassifiable for that air pollutant 

Operating Permit Classifications: 

(1) 18 AAC 50.325(b)(1) - Milne Point Production Facility is a stationary source that emits or 

has the potential to emit 100 TPY or more of a regulated air pollutant 

(2) 18 AAC 50.325(b)(3) - Milne Point Production Facility is a stationary source that contains 

an emission unit subject to one or more of the standards adopted by reference in 

18 AAC 50.040(a) - (c) 

(3) 18 AAC 50.325(c) - Milne Point Production Facility is a stationary source described in 

18 AAC 50.300 (b) through (e) 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 7 of 61 

Section 3. Emission Unit Inventory and Description 

[18 AAC 50.350(d)(2), 1/18/97] 

Emission Units listed in Table 1 have specific monitoring, record keeping, or reporting 

conditions in this permit. Emission unit descriptions and ratings are given for identification 

purposes only.

Table 1 – Emission unit Inventory and Description 

ID Tag No. Location Make/ 

Model or 

Other 

Identifier 

Nominal Maximum Fuel Type Actual 

Date 

Installed 

or 

Modified3

Turbines 

1 PU-0701 Central 

Facilities 

Pad (CFP) 

GE LM-2500 29,500 hp ISO 29,500 hp ISO Fuel gas & 

Liquid Fuel 

1985 

1A PU-0701A5 CFP GE LM2500 

DLE 

29,500 hp ISO 29,500 hp ISO Fuel Gas To Be 

Determined 

2 PU-0801 CFP GE LM-2500 29,500 hp ISO 29,500 hp ISO Fuel gas & 

Liquid Fuel 

1985 

Heaters 

3 H-5302A CFP Thermoflux 30.0 MMBtu/hr 35.0 MMBtu/hr Fuel Gas 1995 

4 H-5302B CFP Thermoflux 30.0 MMBtu/hr 35.0 MMBtu/hr Fuel Gas 1995 

5 H-4510A E-Pad Latoka 14.4 MMBtu/hr 14.4 MMBtu/hr Fuel Gas 19954 

6 H-4510B E-Pad Latoka 14.4 MMBtu/hr 14.4 MMBtu/hr Fuel Gas 19954

7 H-5701A CFP Thermoflux 22.7 MMBtu/hr 29.0 MMBtu/hr Fuel Gas & 

Liquid Fuel 

1985 

8 H-5701B CFP Thermoflux 22.7 MMBtu/hr 29.0 MMBtu/hr Fuel Gas & 

Liquid Fuel 

1985 

9 H-2001A B-Pad Thermoflux 9.8 MMBtu/hr 12.0 MMBtu/hr Fuel Gas 1985 

10 H-2001B B-Pad Thermoflux 9.8 MMBtu/hr 12.0 MMBtu/hr Fuel Gas 1985 

Emergency Engines 

11 PU-0101A CFP Detroit Diesel 1,500 hp 1.5 MW Liquid Fuel 1985 

12 PU-0101B CFP Detroit Diesel 1,500 hp 1.5 MW Liquid Fuel 1985 

13 PU-0101C CFP Detroit Diesel 1,500 hp 1.5 MW Liquid Fuel 1985 

14 PU-0110A CFP Cummins 187 hp 187 hp Liquid Fuel 1985 

15 PU-0110B CFP Cummins 187 hp 187 hp Liquid Fuel 1985 

16 PU-47031 CFP Cat 3304 120 hp 120 hp Liquid Fuel 1985 

17 PU-2004 B-Pad Cummins 600 hp 0.448 MW Liquid Fuel 1985 

Flare2 

18 Flare CFP National, Inc. 0.34 MMscf/day 83 MMscf/day Fuel Gas 1985 

18A Flare CFP Corona 0.125 MMscf/day 83 MMscf/day Fuel Gas To Be 

Determined 

Vents 

21 B-Pad Process Vent 1985 

23 T-6001& T6101B CFP Oil Reserve Tanks 1985 

24 CFP Produced Water Surge Tank 1985 

25 CFP Glycol Dehydration Unit

Table notes: 

1 Emission unit ID 16 is a non-road engine. 

2 Flare nominal flow rate of 0.125 MMscf/day is pilot and purge only. 

3 The actual installation or modification date is provided for historical reference, for determining PSD applicability 

and for the purpose of determining NSPS applicability (except as noted). Modification means any physical 

change in, or change in the method of operation of, an existing stationary source which increases the amount of 

any air pollutant (to which a standard applies) emitted into the atmosphere by the stationary source or which 

results in the emission of any air pollutant (to which a standard applies) into the atmosphere not previously 

emitted, as defined in 40 C.F.R. 60.2 effective 7/1/98. 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 8 of 61 

4 For the purpose of NSPS applicability, the installation or modification date for Emission Unit ID(s) 5 4 and 65 is 

1984 because the heaters were originally installed at the ARCO Alaska Kuparuk River Unit West Sak pilot plant 

in 1984. They were moved from West Sak to MPU E-pad in 1995. 

5 BPXA is replacing Emission Unit 1 (Tag No. PU-0701), with Emission Unit 1A (Tag No. PU-0701A). 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 9 of 61 

Section 4. Emission Fees 

1. 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 pollutants 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 

1.1 the stationary source's assessable potential to emit of 1,383 TPY; or 

1.2 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 50.346(a)(1), 5/3/02 and 18 AAC 50.350(c) & 50.400 – 50.420, 1/18/97] 

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

2.1 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., Juneau, AK 99801-1795; 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 

2.2 if no estimate is received 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 1.1. 

[18 AAC 50.346(a)(1), 5/3/02 and 18 AAC 50.350(c) & 50.400 – 50.420, 1/18/97] 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 10 of 61 

Section 5. Emission Unit-Specific Requirements 

Fuel-Burning Equipment 

3. Visible Emissions. The Permittee shall not cause or allow visible emissions, excluding 

condensed water vapor, emitted from Emission Units 1 and 1A, 2 through 15, 17, 18, and 

18A listed in Table 1 to reduce visibility through the exhaust effluent by any of the 

following: 

a. more than 20 percent for more than three minutes in any one hour1, 

[18 AAC 50.055(a)(1), 1/18/97 and 18 AAC 50.350(d)(1)(C), 6/21/98] 

[40 CFR 52.70, 11/18/98] 

b. more than 20 percent for more than three minutes in any one hour (applies to 

Emission unit ID 18 only), 

[BACT Limit from Permit–to-Operate 8636-AA014, 9/15/85] 

c. more than 20 percent averaged over any six consecutive minutes. 

[18 AAC 50.055(a)(1) & 50.346(c), 5/3/02 and 18 AAC 50.350(d)(1)(C), 6/21/98] 

3.1 For Emission Unit ID(s) 1A, 3 through 6, 9, and 10, burn only gas as fuel. 

Monitoring for these emission units shall consist of an annual certification that each 

of these emission units fired only gas. Report under condition 81 if any fuel is 

burned other than gas. 

3.2 For Emission Unit ID(s) 1, 2, 7, and 8, when operated on gas, monitoring shall 

consist of an annual certification that the emission units fired only gas. If any of 

Emission unit ID(s) 1, 2, 7 and 8 operate on liquid fuel for more than 400 hours in a 

consecutive 12-month period monitor, record, and report according to conditions 

38.1b through 40 for that emission unit. 

3.3 For Emission Unit ID(s) 11 through 15, and 17, as long as they do not exceed 400 

hours of emergency and non-emergency operation per consecutive 12-month period, 

monitoring shall consist of an annual certification of compliance with the opacity 

standard. Otherwise, monitor, record and report visible emissions in accordance 

with conditions 38.1b through 40. 

3.4 For Emission Unit ID 18 and 18A (flares), monitor, record and report in accordance 

with condition 46. 

[18 AAC 50.350(g) - (i) & 50.346(c), 5/3/02] 

 

1

 For purposes of this permit, the “more than three minutes in any one hour” criterion in this condition and 

condition 53 will no longer be effective when the Air Quality Control (18 AAC 50) regulation package effective 

5/3/02 is adopted by the U.S. EPA. The six-minute average standard is enforceable only by the state until the new 

regulations dated May 3, 2002 is approved by EPA into the SIP at which time this standard becomes federally 

enforceable. 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 11 of 61 

4. Particulate Matter. The Permittee shall not cause or allow particulate matter emitted 

from Emission Unit ID(s) 1 and 1A, 2 through 15, 17, 18, and 18A listed in Table 1 to 

exceed 0.05 grains per cubic foot of exhaust gas corrected to standard conditions and 

averaged over three hours. 

[18 AAC 50.346(c), 5/3/02; 18 AAC 50.055(b)(1), 1/18/97 and 18 AAC 50.350(d)(1)(C), 6/21/98] 

4.1 For Emission Unit ID(s) 1A, 3 through 6, 9, and 10, burn only gas as fuel. 

Monitoring for these emission units shall consist of an annual certification that each 

of these emission units fired only gas. Report under condition 81 if any fuel is 

burned other than gas. 

4.2 For Emission Unit ID(s) 1, 2, 7, and 8, when operated on gas, monitoring shall 

consist of an annual certification that the emission units fired only gas. If any of 

Emission unit ID(s) 1 and 2 operate on liquid fuel for more than 400 hours in a 

consecutive 12-month period monitor, record, and report according to conditions 43 

and 45 for that emission unit. If any of Emission unit ID(s) 7 and 8 operate on liquid 

fuel for more than 400 hours in a consecutive 12-month period monitor, record, and 

report according to conditions 41 and 42 for that emission unit. 

4.3 For Emission Unit ID(s) 11 through 15, and 17, as long as they do not exceed 400 

hours of emergency and non-emergency operation per consecutive 12-month period, 

monitoring shall consist of an annual certification of compliance with the particulate 

matter standard. Otherwise, monitor, record and report visible emissions in 

accordance with conditions 43 and 45. 

[18 AAC 50.346(c) & 50.350(g) – (i), 5/3/02] 

4.4 For Emission Unit ID(s) 18 and 18A (flares), the Permittee must annually certify 

compliance with the particulate matter standard. 

[18 AAC 50.346(c) & 50.350(g) – (i), 5/3/02] 

5. Sulfur Compound Emissions. In accordance with 18 AAC 50.055(c), the Permittee shall 

not cause or allow sulfur compound emissions, expressed as SO2, from Emission Unit 

ID(s) 1 and 1A, 2 through 15, 17, 18, and 18A to exceed 500 ppm averaged over three 

hours. 

[18 AAC 50.346(c), 5/3/02; 18 AAC 50.055(c), 1/18/97; and 18 AAC 50.350(d)(1)(C), 6/21/98] 

5.1 For Emission Unit ID(s) 1 and 1A, 2 through 10, and 18, and 18A when using fuel 

gas: 

a. Monitoring conducted as required by condition 17 satisfies the monitoring 

requirements necessary to assure compliance with this condition. 

b. Keep records of analyses conducted in accordance with condition 17.1a. 

c. Report as excess emissions, in accordance with condition 81, whenever the fuel 

combusted causes sulfur compound emissions to exceed the standard of 

condition 5. 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 12 of 61 

d. Include copies of the records required by condition 5.1b with the stationary 

source operating report required by condition 83. 

[18 AAC 50.350(g) - (i), 1/18/97] 

5.2 For Emission Unit ID(s) 1, and 2, 7 and 8, 11 through 15, and 17, when using liquid 

fuel from a North Slope topping plant, the Permittee shall obtain from the topping 

plant the results of a monthly fuel sulfur analysis. 

a. The Permittee shall include in the stationary source operating report required by 

condition 83 a list of the sulfur content measured for each month covered by the 

report. 

b. If the fuel sulfur contains greater than 0.75 percent sulfur by weight, the 

Permittee shall calculate SO2 emissions in PPM using either the SO2 material 

balance calculation in Section 15, or Method 19 of 40 C.F.R. 60, Appendix A7, adopted by reference in 18 AAC 50.040(a). 

c. If SO2 emissions are calculated under condition 5.2b to exceed 500 ppm, the 

Permittee shall report under condition 81. The report shall document the 

calculation under condition 5.2b. 

d. For fuel with a sulfur content greater than 0.75 percent by weight, the Permittee 

shall include in the stationary source operating report required by condition 83 

the calculated SO2 emissions in PPM. 

[18 AAC 50.346(c) & 350(g) - (i), 5/3/02] 

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

Subpart A 

6. NSPS Subpart A Startup, Shutdown, & Malfunction Requirements. The Permittee 

shall maintain records for Emission unit ID(s) 1 through 4 in accordance with 40 CFR 

60.7(b). 

[18 AAC 50.350(h), 5/3/02 & 18 AAC 50.040(a)(1), 7/2/00] 

[40 C.F.R. 60.7(b), Subpart A, 7/1/01] 

7. NSPS Subpart An Excess Emissions and Monitoring Systems Performance (EEMSP) 

Report . For Emission Unit ID(s) 1, 1A, and 2 the Permittee shall comply with 40 CFR 

60.7(c) and (d).

[18 AAC 50.350(i), 1/18/97 & 18 AAC 50.040(a)(1), 7/2/00] 

[40 C.F.R. 60.7(c) & (d), Subpart A, 7/1/01] 

8. NSPS Subpart A, Performance (Source) Tests. At such times as may be required by the 

NSPS Administrator, the Permittee shall conduct source tests for Emission Unit ID(s) 

1,1A, and 2 according to Section 10 of this permit and 40 C. F. R. 60.8 and shall provide 

the Department and EPA with a written report of the results of the source test. 

[18 AAC 50.040(a)(1), 8/15/02] 

[40 C.F.R. 60.8(a)-(e), Subpart A, 7/1/01] 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 13 of 61 

9. NSPS Subpart A Good Air Pollution Control Practice. The Permittee shall maintain 

and operate Emission Unit ID(s) 1 through 4 in accordance with 40 CFR 60.11(d). 

[18 AAC 50.040(a)(1), 8/15/02] 

[40 C.F.R. 60.11(d), Subpart A, 7/1/01] 

10. NSPS Subpart A Credible Evidence. The credible evidence rule of 40 CFR 60.11(g) 

applies to Emission Unit ID(s) 1, 1A, and 2. 

[18 AAC 50.040(a)(1), 8/15/02] 

[40 C.F.R. 60.11(g), Subpart A, 7/1/01] 

11. NSPS Subpart A Concealment of Emissions. The Permittee shall not conceal emissions 

from Emission Unit ID(s) 1, 1A, and 2 as provided in 40 CFR 60.12. Monitoring shall 

consist of an annual certification that the Permittee does not conceal emissions. 

[18 AAC 50.040(a)(1), 8/15/02] 

[40 C.F.R. 60.12, Subpart A, 7/1/01] 

12. NSPS Subpart A, Monitoring. For the continuous monitoring system (CMS) required 

under condition 14.1, the Permittee shall: 

[18 AAC 50.040(a)(1), 8/15/02] 

[40 C.F.R. 60.13(a), 7/1/01] 

12.1 Install and operate the CMS in accordance with 40 C.F.R. 60.13(b). 

[40 C.F.R. 60.13(b), 7/1/01] 

12.2 Install the CMS in accordance with 40 C.F.R. 60.13(f). 

[40 C.F.R. 60.13(f), 7/1/01] 

12.3 Reduce data from the CMS in accordance with 40 C.F.R. 60.13(h). 

[40 C.F.R. 60.13(h), 7/1/01] 

Emission Units Subject to NSPS Subpart Dc, Emission Unit ID(s) 3 and 4 

13. NSPS Subpart Dc Requirements. The Permittee shall maintain records of the amount of 

fuel gas combusted during each day for Emission Unit ID(s) 3 and 4 in accordance with 40 

CFR 60.48c(g) Subpart Dc. 

[18 AAC 50.040(a)(2)(D), 8/15/02] 

[40 C.F.R. 60.48c(g), Subpart Dc, 7/1/01] 

Turbines Subject to NSPS Subpart GG NOX Standard, Emission Unit ID(s) 1, 1A, and 2 

14. NSPS Subpart GG NOX Standard. Except as provided in conditions 15 and 16, the 

Permittee shall not allow the corrected exhaust gas concentration from Emission Unit ID(s) 

1, 1A and 2 to exceed 215 ppmvd of NOX at ISO standard day conditions and 15 percent 

oxygen when firing fuel gas. Emission Unit ID(s) 1 and 2 are exempt from the limit in this 

condition when firing emergency fuel, which includes periods when source tests required 

by condition 22.1 are conducted. 

[18 AAC 50.040(a)(2)(V), 8/15/02] 

 [40 C.F.R. 60.332(a)(2), Subpart GG, 7/1/01] 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 14 of 61 

14.1 Install and operate a continuous monitoring system (CMS) in Emission Unit ID(s) 1 

and 2 to monitor and record the fuel consumption and the ratio of water to fuel being 

fired in the turbines, in accordance with 40 C.F.R. 60.334(a). 

[18 AAC 50.350(g) & (h), 1/18/97] 

[40 C.F.R. 60.334(a), Subpart GG, 7/1/01] 

14.2 Report in accordance with 40 C.F.R. 60.334(c)(1). 

15. Ice Fog Exemption and Reporting. Emission Unit ID(s) 1 and 2 are exempt from 

condition 14 when the Permittee deems ice fog a traffic hazard in accordance with 

40 C.F.R. 60.332(f). Report in accordance with 40 C.F.R. 60.334(c)(3). 

[18 AAC 50.040(a)(2)(V), 8/15/02] 

[40 C.F.R. 60.332(f), Subpart GG, 7/1/01] 

16. Emergency Fuel Exemption and Reporting. Emission Unit ID(s) 1 and 2 are exempt 

from the limit of condition 14 when fired with liquid fuel during circumstances that make 

it impossible to fire fuel gas in the turbines. The Permittee shall report each exemption 

period in accordance with 40 CFR 60.334(c)(4). 

[18 AAC 50.040(a)(2)(V), 8/15/02] 

[40 C.F.R. 60.332(k), Subpart GG, 7/1/01] 

[40 C.F.R. 60.334(c)(4), Subpart GG, 7/1/01]

17. NSPS Subpart GG Sulfur Standard. The Permittee shall not allow the sulfur content for 

the fuel burned in Emission Unit ID(s) 1, 1A, and 2 to exceed 0.8 percent by weight. 

[18 AAC 50.040(a)(2)(V), 8/15/02] 

[40 C.F.R. 60.333(b), Subpart GG, 7/1/01] 

17.1 Determine compliance monthly with the fuel sulfur content standard in this condition 

as follows: 

[40 C.F.R. 60.334 & 60.335(d), Subpart GG, 7/1/01] 

a. For gaseous fuels, monitor, record, and report the sulfur content of the fuel gas 

fired in Emission Unit IDs 1, 1A and 2 in accordance with either 40 CFR 

60.334(b), (c) and §60.335(d), or the custom schedule and plan approved 

August 28, 2002, or a revised custom schedule and plan approved in 

accordance with 40 CFR 60.334(b)(2). 

b. For liquid fuels, determine the sulfur content using one of the methods specified 

in ASTM D 2880-71, or an EPA approved alternative method. 

c. The fuel sulfur analysis required under this condition may be performed by the 

owner or operator, a service contractor retained by the owner or operator, the 

fuel vendor, or any other qualified agency. 

[40 C.F.R. 60.335(e), Subpart GG, 7/1/01] 

17.2 Keep records of analysis as required by condition 17.1. 

17.3 The Permittee shall semi-annually report to the EPA results of all sulfur monitoring 

required by this condition. 

[40 C.F.R. 60.334(c)(2), Subpart GG, 7/1/01] 
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17.4 For the purpose of EEMSP reports and summary report required under condition 7, 

the Permittee shall report in accordance with 40 C.F.R. 60.334(c)(2). 

[18 AAC 50.350(i), 1/18/97] 

[40 C.F.R. 60.334(c)(2), Subpart GG, 7/1/01] 

18. Periodic Monitoring, Recordkeeping and Reporting for NSPS Subpart GG NOX

Emission Standard. In addition to the NSPS monitoring, recordkeeping, and reporting 

requirements of condition 15, source tests conducted in accordance with conditions 23.1a 

and 23.4 shall be used as the basis to determine compliance with the NOx emission limit of 

condition 15 for Emission Unit ID(s) 1 and 2. For Emission Unit ID 1A, conduct an initial 

performance test in accordance with 40 CFR 60.8. Submit reports in accordance with 

condition 81 any time the NOx emission rate exceeds the standard in condition 15. 

[18 AAC 50.350(g) - (i), 1/18/97] 

[18 AAC 50.220(a) - (c), 1/18/97] 

19. Turbine NOX and CO Monitoring Requirements. To monitor compliance with the NOX

PSD avoidance standard and the CO BACT limits in Table 5, the Permittee shall monitor 

process parameters hourly and calculate the NOX and CO emission rates in pounds per 

hour (pph) no less than once per month for Emission Unit ID(s) 1, 1A, and 2 in accordance 

with conditions 19.1, 19.3, or 20.3 as follows: 

[Construction Permit No. 0073-AC023, 7/13/01] 

19.1 Unless required to use a CEMS by condition 20.3 for either NOX or for CO, calculate 

emission rates for Emission Unit ID(s) 1 and 2 using the best-fit correlation most 

recently approved by the Department or most recently submitted for approval by the 

Permittee under condition 21.5 or condition 22.3. 

19.2 Calculate NOx and CO emission rates for Emission Unit ID 1A hourly using the 

most recently submitted emission index from condition 24.2 and fuel 

19.3 Install a CEMS for NOX or for CO as indicated in condition 20, and 

a. no later than 120 days after submitting the report for the second failing test if 

two consecutive Relative Accuracy (RA) tests performed under condition 22.1 

for the Department-approved correlation exceed the limits in conditions 

19.3a(i) or 19.3a(ii). 

(i) twenty percent when the RM value is used in the denominator of the RA 

equation in 40 CFR 60, Appendix B, Performance Specification 2, Section 

12, Equation 2-6 (average emissions during test are greater than 50 percent 

of the emission standard) or 

(ii) ten percent when the applicable emission standard is used in the 

denominator of the RA equation in 40 CFR 60, Appendix B, Performance 

Specification 2, Section 12, Equation 2-6 (average emissions during test 

are less than 50 percent of the emission standard), and 

b. calculate an hourly emission rate (lb/hr) using a fuel specific emission factor 

(lb/MMBtu) and a heat consumption value (MMBtu/hr) and as follows: 
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(i) Determine the fuel specific emission factor from NOX or CO and O2

measured volume concentrations and Method 19. 

(ii) Use consistent heating values (higher or lower heating value) throughout 

the analysis. 

(iii) If the “F” factor from Table 19-2 in Method 19 is used in the calculations, 

use the higher heating value in all calculations. 

20. Continuous Emissions Monitoring System (CEMS). If monitoring NOX and CO under 

condition 20.3, the Permittee shall use a CEMS as follows: 

[Construction Permit No. 0073-AC023, 7/13/01] 

20.1 Within 90 days of CEMS installation under condition 20.3, conduct a relative 

accuracy test of the CEMS as set out in 65 FR 61744, Performance Specification 2 

(PS2) for NOX and Performance Specification 4 (PS4) for CO, dated October 17, 

2000. A CEMS is not acceptable if it does not meet the limits set out in Section 13.2 

of PS2. 

20.2 Within 60 days of completing the Relative Accuracy (RA) test under condition 20.1, 

submit a CEMS quality assurance, quality control (QA/QC) plan to the Department 

for approval. 

20.3 Record the results of the RA test conducted under condition 20.1. 

20.4 Report to the Department 

a. the results of the RA test required by condition 20.1 as set out in Section 8 of 

PS2 within 60 days of completing the RA tests; and 

b. a copy of the plan required by condition 20.2 upon completion of the plan. 

21. Best-Fit Correlation Method. If monitoring NOX and CO under condition 20.1, the 

Permittee shall develop best-fit correlations 

a. between NOX emission rates from source tests and turbine process parameters, 

and 

b. between CO emission rates from source tests and turbine process parameters, as 

follows: 

[Construction Permit No. 0073-AC023, 7/13/01] 

21.1 Notify the Department of intention to develop a best-fit correlation for emission 

monitoring, and submit a source test plan to the Department in accordance with 

condition 73, including 
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a. identification of the proposed process parameters for which the Permittee elects 

to measure a parametric monitoring correlation, and 

b. a description of the monitoring methodology accuracy and precision of 

methodology and sampling rates of each parameter. 

21.2 Conduct three sets3 of initial Reference Method (RM) source tests as described in 

condition 69 at each of three loads (high, medium, and low), on each turbine, for 

each of the four operating scenarios listed below, for NOX and CO. 

a. Fuel gas, without DWI, 

b. Fuel gas, with DWI, 

c. Liquid Fuel, without DWI, and 

d. Liquid Fuel with DWI 

21.3 During the RM source tests required under condition 21.2, collect and record the 

process parameters identified in condition 21.1a for the purpose of developing 

parametric correlations for NOX and CO emission rates for both fuel gas and liquid 

fuel. 

21.4 Using the RM test results from condition 21.2, develop best-fit correlations for 

emission rates based on turbine process parameters as follows: (The correlations may 

also be based on SSPOWGEN (software program) or other vendor data as well as the 

RM source tests.) 

a. NOX/fuel gas, with and without DWI; 

b. NOX/liquid fuel, with and without DWI; 

c. CO/fuel gas, with and without DWI; and 

d. CO/liquid fuel, with and without DWI. 

21.5 Within 60 days after completing the RM tests under condition 21.2, submit to the 

Department for written approval a report that describes the best-fit correlation 

development, including the methodology, assumptions, analysis (with sample 

calculations), supporting notes, and a list of all process parameters used in the 

correlations with an analysis of their statistical relevance for the correlation (i.e. an r2

analysis of curve fit). 

21.6 Develop QA procedures for the process parameters used in the correlation developed 

under condition 21.5. 

 

3

 One set = one run, so three runs are required at high load, three at medium and three at low. 6

 One set = one run, so three runs are required at high load, three at medium and three at low. 
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21.7 Include with the stationary source operating report required by condition 83 copies 

of the QA procedures developed under condition 21.6. 

22. Relative Accuracy (RA) Test Procedures for NOX and CO. Except as provided in 

condition 22.4, the Permittee shall determine the RA of all correlations most recently 

approved under condition 21.5 or condition 22.3 annually as follows: 

[Construction Permit No. 0073-AC023, 7/13/01] 

22.1 No more than 12 months after the previous series of RM tests, conduct RM tests for 

NOX and CO as follows: 

a. Conduct a minimum of three sets6 RM source tests as described in condition 69 

at each of three loads (high, medium, and low), on one turbine (in even years on 

Emission Unit ID 1 and in odd years on Emission Unit ID 2), for each of the 

four following operating scenarios: 

(i) Fuel gas, without DWI, 

(ii) Fuel gas, with DWI, 

(iii) Liquid fuel, without DWI, and 

(iv) Liquid fuel, with DWI. 

b. Record each statistically relevant process parameter during each RM source test 

no less than once every 15 minutes. Mark the beginning and end of each RM 

source test on the output record. 

c. Record the NOX and CO emission concentrations in ppm for each RM source 

test period ("RM value") for each of the operating scenarios in condition 22.1a. 

d. Determine the integrated average NOX and CO emission rates in pph for each 

RM test period using the best fit correlations approved by the Department under 

condition 21.5 or condition 22.3. 

22.2 Calculate the relative accuracy of a correlation compared to a RM test as follows: 

a. If the RM has an instrumental or integrated non-instrumental sampling 

technique, make a direct comparison of the RM value and the correlation value. 

b. If the RM has a grab sampling technique, first average the results from all grab 

samples taken during the test run, and then compare this average value against 

the value obtained from the correlation during the run. 

c. Using the procedures in 40 CFR 60, Appendix B, Performance Specification 2, 

Section 12 and summarizing the results on a data sheet similar to that shown in 

Section 18 calculate the 
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(i) arithmetic mean of the difference between the "RM value" and the 

"correlation value", 

(ii) standard deviation, 

(iii) confidence coefficient, and 

(iv) relative accuracy. 

22.3 Based on RA test results, propose revisions to the best-fit correlation. Within 60 

days after completing the RM tests, submit to the Department for written approval a 

report that describes the best-fit correlation revision, including the methodology, 

assumptions, analysis (with sample calculations), supporting notes, and a list of all 

process parameters used in the correlations with an analysis of their statistical 

relevance for the correlation (i.e. an r2 analysis of curve fit). Revise QA procedures 

for the process parameters used in the best-fit correlation most recently approved by 

the Department. 

22.4 If five consecutive annual RA verifications of any correlation are less than the limits 

in Condition 20.3 the Permittee may decrease the testing frequency to once every 24 

months, with the Department's concurrence. 

22.5 Include with the stationary source operating report required under condition 83 

copies of the results of all RM tests (including any rejected test results) conducted 

under condition 22.1a. 

23. Emission Index for Emission Unit ID 1A. In conjunction with the testing required by 

condition 19, conduct a CO emissions test at four loads in the normal operating range of 

Emission Unit ID 1A. 

23.1 Correct the NOx and CO values from the test to 15 percent oxygen. Take the highest 

value from all the results and add a 20 percent safety margin. 

23.2 Using the results from condition 24.1, calculate an emission index for Emission Unit 

ID 1A in lb/MMBtu based on the lower heating value of the fuel for NOx and CO 

using the methodology in 40 CFR 60 Appendix A Method 19. 

Emission Unit Subject to Owner Requested Limit to Maintain the HAP-minor Status of 

the Stationary Source 

24. Operation of Closed Vent System. The Permittee shall operate the closed vent system 

for Emission Units ID 25 (Glycol Dehydration Unit) a minimum of 2400 hours per 

calendar year to recycle the vent scrubber hydrocarbons back into the third stage 

compression for recovery. 

[18 AAC 50.335(g)(1), 1/18/97] 

24.1 Monitor and record the monthly and year-to-date operating time of the closed vent 

system. 
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24.2 Include with the stationary source operating report required by condition 83, copies 

of the records required by condition 24.1. 

24.3 If the total number of hours of closed vent system operation for the calendar year is 

less than 2400 hours, then 

a. estimate HAP emissions from the stationary source, 

b. submit a report in accordance with condition 81, and 

c. reevaluate the HAP-major status of the stationary source. 

Emission Units Subject to Owner Requested Limits for Ambient Air Quality Protection 

25. Liquid Fuel Sulfur Requirements. The Permittee shall burn liquid fuel with no greater 

than 0.30 percent sulfur by weight in any of the fuel-burning equipment listed in Table 1. 

Monitor, record, and report as follows: 

[Construction Permit No. 0073-AC023, 7/13/01] 

25.1 For Emission Unit ID(s) 1 and 2 (Subpart GG turbines) obtain records of the sulfur 

content of the liquid fuel as required in condition 17.1. For all other fuel burning 

equipment listed in Table 1 except for Emission Unit ID(s) 1 and 2, obtain a record 

of the sulfur content of the liquid fuel as required in condition 5.2. 

25.2 Keep records of the results of each liquid fuel sulfur analysis. 

25.3 Submit a report in accordance with condition 81 whenever liquid fuel sulfur content 

exceeds the sulfur limit in condition 25. 

25.4 Submit with the stationary source operating report required by condition 83, copies 

of the records required under condition 25.2. 

[18 AAC 50.350(g) - (i), 7/2/00] 

26. Liquid Fuel Consumption Limit. The Permittee shall burn no more than one million 

gallons of liquid fuel per 12 consecutive months at the CFP, B-Pad, and E-Pad in all of the 

equipment listed in Table 1 and all other fuel burning equipment that may be present on 

the specified pads, except for fuel burned in motor vehicles and in insignificant Emission 

Units as listed at 18 AAC 50.335(r), (s), and (t). The Permittee shall not exclude Emission 

Units on rotary drill rigs as insignificant Emission Units. 

[Construction Permit No. 0073-AC023, 7/13/01] 

26.1 Measure the monthly total liquid fuel used by Emission Unit ID(s) 1 and 2 using the 

fuel meters required by condition 14.1. For other fuel burning emission units, the 

fuel use may be estimated by calculations approved by the Department. Fuel meters, 

if used, must be calibrated using NIST traceable standards and must be accurate to 

within plus or minus five percent. 
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26.2 Calculate and record the total liquid fuel burned in the previous 12 consecutive 

months. 

26.3 Submit a report in accordance with condition 81 whenever the liquid fuel quantity in 

gallons exceeds the liquid fuel limit in condition 26. 

26.4 Include with the stationary source operating report required by condition 83, copies 

of the records required under condition 26.2 for each rolling 12-month total during 

the reporting period. 

[18 AAC 50.350(g) - (i), 7/2/00] 

27. Fuel Gas Sulfur Requirements. The Permittee shall burn fuel gas with no greater than 

100 ppmvd H2S 12-month rolling average in any of the fuel burning equipment listed in 

Table 1. 

[Construction Permit No. 0073-AC023, 7/13/01] 

27.1 Monitor and record the H2S content of the fuel gas as required in condition 17.1a and 

17.2. 

27.2 Submit a report in accordance with condition 81 whenever the 12-month rolling 

period average fuel gas H2S content exceeds the H2S limit in condition 27. 

27.3 Include with the stationary source operating report required by condition 83, a 

summary of the consecutive 12-month period average fuel gas H2S concentration for 

each month of the reporting period. 

[18 AAC 50.350(g) - (i), 7/2/00] 

28. Annual Limits. The Permittee shall comply with the annual operating hour limits shown 

in Table 2. 

[Construction Permit No. 0073-AC023, 7/13/01] 
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Table 2 – Annual Limits 

Emission Unit Limits 

7 and 8 Operate no more than 200 hours during any 12 

consecutive months, combined, while firing liquid fuel. 

11, 12, and 13 Operate no more than 900 hours during any 12 

consecutive months, combined. 

14 and 15 Operate no more than 600 hours during any 12 

consecutive months, combined. 

17 Operate no more than 300 hours during any 12 

consecutive months. 

16 Operate no more than 1,344 hours per year while at CFP, 

B-pad, and E-pad. 

18 and 18A Operate sequentially except during periods of transfer of 

gas from one flare to the other. The period of 

overlapping operations should be the minimum practical, 

and shall not exceed 72 hours. The combined output 

during overlapping operations shall at no time exceed 

the combined output greater than 83 MMscf/day. 

28.1 The Permittee shall maintain a log that includes the operating time in hours for each 

emission unit listed in Table 2. Each month, calculate the monthly operating time in 

hours for each emission unit listed in Table 2 and summarize the operating time in 

hours for the previous twelve months. 

28.2 Submit a report in accordance with condition 81 whenever the previous 12-month 

operating hours summarized under condition 28.1 exceed the limits listed in Table 2. 

28.3 Include with the stationary source operating report required by condition 83, copies 

of the records required by condition 28.1. 

[18 AAC 50.350(g) - (i), 7/2/00] 

29. Daily Operating Limits. The Permittee shall comply with the daily operating scenarios 

shown in Table 3 and as follows: 

a. Operate under scenario 1 except as provided in condition 29.b. 

b. Operate under scenarios 2 or 3 only if fuel gas is unavailable or during source 

testing. Prorate operation of each scenario used during each day. 

[Construction Permit No. 0073-AC023, 7/13/01] 
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Table 3 – Daily Operating Limits7

Emission Scenario 1 Scenario 2 Scenario 3 

Unit ID Fuel Limit Fuel Limit Fuel Limit 

1 Fuel Gas None 

2 Fuel Gas None 

Fuel Gas/ 

Liquid Fuel 

Combined 

total of 900 

lb SO2/day 

Fuel Gas/ 

Liquid Fuel 

Combined 

total of 

900 lb 

SO2/day 

7 Fuel Gas None Liquid Fuel None Liquid Fuel 

8 Fuel Gas None Liquid Fuel None Liquid Fuel 

Combined 

total of 24 

hr/day 

11 Liquid Fuel Liquid Fuel Liquid Fuel 

12 Liquid Fuel Liquid Fuel Liquid Fuel 

13 Liquid Fuel 

Combined 

total of 

76.5 MWhr/day 

Liquid Fuel 

Combined 

total of 15.0 

MW-hr/day Liquid Fuel 

Combined 

total of 

72.0 MWhr/day 

14 Liquid Fuel Liquid Fuel Liquid Fuel 

15 Liquid Fuel 

Combined 

total of 12 

hr/day 

Liquid Fuel 

Combined 

total of 16 

hr/day 

Liquid Fuel 

Combined 

total of 12 

hr/day 

17 Liquid Fuel 9.8 MWhr/day 

Liquid Fuel 9.8 MWhr/day Liquid Fuel 9.8 MWhr/day 

29.1 The Permittee shall maintain a daily log for each emission unit listed in Table 3 that 

includes the operating scenario and compliance data. Each month, summarize the 

daily operating scenarios for the month. 

29.2 Submit a report in accordance with condition 81 any violations of the daily operating 

scenarios in Table 3. 

29.3 Include with the stationary source operating report required by condition 83, copies 

of the records required by condition 29.1. 

[18 AAC 50.350(g) - (i), 7/2/00] 

Heaters Subject to BACT Limits 

30. Heater CO and NOX BACT Limits. The Permittee shall not cause or allow CO or NOX

emissions from Emission Unit ID(s) 3 through 10 to exceed the limits in Table 4 below. 

[Construction Permit No. 0073-AC023, 7/13/01] 

30.1 Monitor, record and report by following established preventative maintenance 

guidelines, and maintaining records of maintenance completed. Retain maintenance 

records for five years, and submit records to the Department upon request. 

 

7

 Equipment not listed in Table 3 is not subject to any daily operating limits. 
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Table 4 – Heater BACT Limits 

Pollutant Emission 

Unit IDs 

Make/Model Emission Limit 

(short term) per 

Individual Heater 

Annual Emission Limit for 

Heaters (tpy) 

3, 4, 9, and 10 Thermoflux 

5 and 6 Latoka 

0.2 lb/MMBtu 

7 and 8 0.2 lb/MMBtu 

(when firing fuel gas) 

CO 

Thermoflux 

5 lb/1000 gallons 

(when firing liquid 

fuel) 

No Limit 

3 and 4 Thermoflux 0.05 lb/MMBtu 

5 and 6 Latoka 0.08 lb/MMBtu 

7 and 8 0.08 lb/MMBtu 

(when firing fuel gas) 

Thermoflux 

11.3 lb/hr (based on 

HHV, when firing 

liquid fuel) 

NOX 

9 and 10 Thermoflux 0.08 lb/MMBtu 

No Limit 

30.2 Do not operate Emission Unit ID(s) 9 and 10 on liquid fuel at any time. 

30.3 No later than 180 days after permit issuance, conduct source tests on Emission Unit 

IDs 3 and 5 for NOX to ascertain compliance with the emission limit in this condition 

for Emission Unit IDs 3 through 6, when firing natural gas, except as provided in 

condition 30.4. Conduct source tests in accordance with the requirements in Section 

10. Determine the NOX emission rate for the heater using exhaust properties 

determined by 40 C.F.R. 60, Appendix A, Method 19, and exhaust gas 

measurements in Section 10. Determine compliance with the NOX emission rate 

using 40 C.F.R. 60, Appendix A, Method 19. 

30.4 The requirement to conduct source tests on Emission Unit IDs 3 and 5 under 

condition 30.3 is waived if the Department determines that previous source tests for 

these emission units are acceptable. 

30.5 Submit a report in accordance with condition 81 any exceedance of a NOX emission 

limit specified in Table 4. 

[18 AAC 50.350(g) - (i), 7/2/00] 

[Construction Permit No. 0073-AC023, 7/13/01] 

Turbines Subject to BACT and PSD Avoidance Limits 

31. Turbine CO, NOX, SO2, and PM BACT and PSD Avoidance Limits. The Permittee 

shall not cause or allow CO, NOX, SO2, and PM emissions from Emission Unit ID(s) 1, 

1A, and 2 to exceed the limits in Table 5 below. 

[Construction Permit No. 0073-AC023, 7/13/01] 
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Table 5 – Turbine BACT and PSD Avoidance Limits 

Pollutant Make/Model 

Emission Unit 

IDs 

BACT Limit 

Emissions (short term) per 

Individual Turbine 

PSD Avoidance Limits 

Annual Emissions for 

Turbines (tpy) 

CO 70 pph 94.4 each (BACT annual limit) 

NOX 184 ppmvd @ 15% O2 and ISO 

conditions 

625 combined 

SO2 No Limit 0.30% sulfur by weight in liquid fuel, 

or 100 ppmvd H2S in gaseous fuel 

PM 

GE LM2500 DLE, 

Emission Unit ID 

1A and GE LM2500, Emission 

Unit IDs 1 and 2 

No Limit 28 combined 

Notes: 1) All emission limits for NOX refer to full load ISO conditions. 

 2) All emission limitations are annual average unless otherwise noted. 

32. Turbine NOX Load Limits. The Permittee shall comply with the NOX BACT limit in 

Table 5 by limiting operational load and/or using Direct Water Injection (DWI) technology 

for each of the turbines. 

 [Construction Permit No. 0073-AC023, 7/13/01] 

32.1 If not using Direct Water Injection (DWI): 

a. When using natural gas, operate at no greater than 22,156 kW (generator 

output) each. 

b. When using liquid fuel: 

(i) except for DWI start-up periods, operate at no greater than 8,122 kW 

(generator output) each. 

(ii) during DWI startup, operate at no greater than 9,500 kW each. 

(iii) during emergency fuel switches, operate for no more than 2 hours without 

DWI. 

(iv) during source testing, operate at minimum loads required to accomplish 

the source test. 

(v) during scheduled maintenance of the AquaChem water treatment system, 

operate for no more than 2 hours without DWI. 

32.2 If using DWI, load is restricted to maximum load at which compliance with the NOX

BACT limit in Table 5 was demonstrated for each fuel during any source test 

required under conditions 21.2b, 21.2d, 22.1a(ii), or 22.1a(iv). 
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33. Monitoring, Recordkeeping, and Reporting for Turbine BACT and PSD Avoidance 

Limits. The Permittee shall monitor Emission Unit ID(s) 1, 1A, and 2 as follows: 

[Construction Permit No. 0073-AC023, 7/13/01] 

33.1 For NOX BACT emission limit conduct source tests as required in condition 21.2, 

22.1, 22.4, and 24 to demonstrate compliance with the NOX BACT limit in Table 5. 

33.2 For NOX BACT load limit record the load in kW for Emission Unit IDs 1, 1A, and 2 

for each hour of the day and whether DWI was used. 

33.3 For NOX PSD avoidance limit no later than the fifteenth day of each calendar month, 

calculate the NOX emissions in tons/month for the previous calendar month using 

Equation 1 below. Calculate and record the 12-month rolling total NOX emissions 

for both turbines by adding the total NOX emissions for the prior calendar month to 

the monthly totals for the previous months. 

Equation 1 ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ ⎟ ×

⎠

⎞ ⎜

⎝

⎛ ⎟ ×

⎠

⎞ ⎜

⎝

⎛ ⎟ =

⎠

⎞ ⎜

⎝

⎛

lb

ton

mo

hr

hr

lb ER

mo

tons NO emissions X 2000

 Where, 

 ER = Average hourly NOX emission rate for previous month in pph from 

condition 19 

33.4 For CO Hourly BACT limit monitor and calculate the CO emission rate in pph as 

indicated in condition 19. 

33.5 For CO Annual BACT limit no later than the fifteenth day of each calendar month, 

calculate CO emissions in tons/month for the previous calendar month using 

Equation 2 below. Calculate and record the 12-month rolling total CO emissions for 

both turbines by adding the total CO emissions for the prior calendar month to the 

monthly totals for the previous months. 

Equation 2 ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ ⎟ ×

⎠

⎞ ⎜

⎝

⎛ ⎟ ×

⎠

⎞ ⎜

⎝

⎛ ⎟ =

⎠

⎞ ⎜

⎝

⎛

lb

ton

mo

hr

hr

lb ER

mo

tons CO emissions

2000

 Where, 

 ER = Average hourly CO emission rate for previous month in pph from 

condition 19 

33.6 For SO2 PSD avoidance limit comply with the fuel sulfur limits, monitoring, 

recordkeeping and reporting requirements set out in conditions 25 and 27. 

33.7 For PM PSD Avoidance Limit 
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a. For fuel gas: 

(i) Except as provided in condition 33.7a(ii), calculate and record the total 

amount of fuel gas in MMscf used in both turbines for each month using 

the readings taken under condition 14.1; 

(ii) for any time period during which the unit is operational and the fuel 

consumption records are missing or incorrect, estimate fuel consumption 

based on the design firing rate of the unit for the prevailing ambient 

temperature; 

(iii) add the totals determined under condition 33.7a(i) or 33.7a(ii) to the 

monthly totals for the previous 11 months to get 12 month fuel gas usage 

in MMscf/yr; 

(iv) calculate the 12 month PM-10 emissions from fuel gas using Equation 3; 

and 

Equation 3 E (EF)(F)(0.0005tons / lb) NG =

 Where: 

 ENG = PM-10 emissions from fuel gas in TPY 

 EF = PM-10 emission factor in lb/MMscf as described in condition 33.7a(v) 

 F = 12-month fuel gas usage in MMscf/yr as calculated in condition 

33.7a(iii) 

(v) determine the emission factor to be used in condition 33.7a(iv) as follows. 

(A) Until a source test is required by condition 33.7c, use an initial 

emission factor of 6.02 lb/MMscf (AP-42 Supplement F, 4/00, 

Table 3.1-2a). 

(B) Once a source test required by condition 33.7c has been 

conducted, use the PM emission factor for fuel gas in lb/MMscf 

from the source test. 

b. For liquid fuel: 

(i) Except as provided in condition 33.7b(ii), calculate and record the total 

amount of liquid fuel in gallons used in both turbines for each month using 

the readings taken under condition 14.1; 

(ii) for any time period during which the unit is operational and the fuel 

consumption records are missing or incorrect, estimate fuel consumption 

based on the design firing rate of the unit for the prevailing ambient 

temperature; 
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(iii) add the totals determined under condition 33.7b(i) or 33.7b(ii) to the 

monthly totals for the previous 11 months to get 12 month liquid fuel 

usage in gal/yr; 

(iv) calculate the 12 month PM-10 emissions from liquid fuel using Equation 

4; and 

Equation 4 E (EF)(F)(HV )(0.0005tons/ lb) D =

 Where: 

ED = PM-10 emissions from liquid fuel in TPY 

EF = PM-10 emission factor in lb/MMBtu, based on High Heating Value 

(HHV), as described in condition 33.7b(v) 

F = 12-month liquid fuel usage in gal/yr as calculated in condition 

33.7b(iii) 

HV = HHV of liquid fuel 

(v) determine the emission factor to be used in condition 33.7b(iv) as follows. 

(A) Until a source test is required by condition 33.7c, use an initial 

emission factor of 0.012 lb/MMBtu (AP-42, Supplement F, 4/00, 

Table 3.1-2a). 

(B) Once a source test required by condition 33.7c has been 

conducted, use the PM emission factor for liquid fuel in 

lb/MMBtu, based on HHV, from the source test. 

c. No later than the fifteenth day of each calendar month, calculate and record the 

12-month total PM-10 emissions for the turbines by adding emissions from 

conditions 33.7a(iv) and 33.7b(iv). The first time that the 12-month total from 

this condition exceeds 26 tons, determine PM-10 emission factors for the 

turbines, in lb/MMscf for fuel gas firing and in lb/MMBtu (based on HHV), for 

liquid fuel-firing, with and without DWI, by conducting source tests in 

accordance with condition 69. Submit a source test plan in accordance with 

condition 73 no later than 60 days after the end of the month in which the 12-

month total exceeded 26 tons. Keep records documenting the emissions 

calculations. 

33.8 Notify the Department per condition 81 should the twelve-month consecutive 

summation of emissions of any air pollutant exceed the limit for that pollutant in 

Table 5. 

33.9 Notify the Department per condition 81 any violations of the operating load limits 

for Emission Unit ID 1, 1A, or 2 in condition 32. 
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33.10 Notify the Department per condition 81 whenever the CO hourly emission rate 

exceeds the CO hourly emission limit in Table 5. 

33.11Report the monthly and the consecutive twelve-month period summation of 

emissions, for each month of the reporting period, with each stationary source 

operating report required by condition 83. 

33.12 Submit with the operating report required by condition 83, copies of the records 

required by condition 33.2. 

[18 AAC 50.350(g) - (i), 7/2/00] 

[Construction Permit No. 0073-AC023, 7/13/01] 

Vents Subject to BACT Limits 

34. Vent VOC BACT. 

34.1 The Permittee shall limit Well Pad B vents to 36.5 tpy of VOC emissions. 

34.2 Monitoring shall consist of an annual certification under condition 84 that the 

requirements of this condition have been met during the reporting period. 

34.3 Monitor by calculating monthly VOC emissions from Well Pad B as follows: 

a. Determine VOC content of a representative sample of the gas stream at Well 

Pad B within 90 days of permit issuance and at least once each per rolling 

twelve months thereafter using ASTM D-1945 or alternate procedure approved 

in writing by the Department, 

b. Determine the mass of VOC’s per standard cubic feet of fuel gas using the 

analysis conducted in condition 34.3(a), 

c. Monitor the fuel gas stream flow rate by installing a calibrated rotometer, 

d. Record the actual fuel gas flow rate, gas temperature, and gas pressure at least 

once each month, 

e. Calculate the total VOC emissions (tons) vented at Well Pad B each month 

using the recorded gas flow rate, gas temperature, gas pressure, the most recent 

VOC content, and total number of hours in the month, 

f. Determine the total VOC quantity vented during the previous 12 months by 

summing the monthly VOC emissions, and 

g. Report the VOC emissions in the Facility Operating Report required by 

Condition 83. 

[Construction Permit No. 0073-AC023, 7/13/01] 

 [18 AAC 50.350(g) - (i), 7/2/00] 

Fuel Consumption Monitoring 

35. The Permittee shall monitor, record, and report fuel consumption at the stationary source 

as follows: 

[Operating Permit No. 9673-AA005, 1/17/97] 
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35.1 Monitor and record the monthly total volume of fuel consumed by the turbines 

(Emission Unit ID(s) 1, 1A, and 2 combined), heaters (Emission Unit ID(s) 3 

through 10 combined), engines (Emission Unit ID(s) 11 through 17 combined) and 

flares (Emission Unit ID(s) 18 and 18A combined). For the turbines, use the 

monitoring device required by condition 14.1 to measure the fuel consumption. For 

all other fuel-burning emission units, the Permittee may estimate fuel use. 

35.2 Include with the stationary source operating report required under condition 83, the 

monthly fuel consumption (MMscf/month or gallons/month) for each of the 

combined emission unit groups stated in condition 35.1 and the monthly total 

quantity of fuel consumed at the stationary source, for the period covered by the 

report. 

[18 AAC 350(g) – (i), 1/18/97] 

Hours of Operation Monitoring for Fuel-fired Emission Units 

36. The Permittee shall monitor, record, and report the hours of operation as follows: 

[Operating Permit No. 9673-AA005, 1/17/97] 

36.1 Monitor and record the monthly operating time for each fuel-burning emission unit 

listed in Table 1, excluding flares. 

36.2 Include with the stationary source operating report required under condition 83, the 

monthly hours of operation for each fuel-burning emission unit listed in Table 1, 

excluding flares. 

[18 AAC 350(g) – (i), 1/18/97] 

37. Flaring. For flaring events the Permittee shall monitor, record, and report as follows: 

[Construction Permit No. 0073-AC023, 7/13/01] 

37.1 Calculate the monthly estimated emissions of PM, NOX, SO2, and CO using 

published emission factors. 

37.2 Include with the stationary source operating report required under condition 83, 

copies of the calculations required under condition 37.1. 

[18 AAC 50.350(g) - (i), 6/21/98] 
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Section 6. Visible Emissions and PM Monitoring, Recordkeeping and Reporting 

38. Visible Emissions Monitoring. The Permittee shall observe the exhaust of Emission Unit 

ID(s) 1, 2, 7, 8, 11 through 15, and 17, for visible emissions using the Method 9 Plan under 

condition 38.1. 

38.1 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. 

a. First Method 9 Observation. For Emission Unit ID(s) 11 through 15, and 17, 

observe exhaust for 18 minutes within six months after the effective date of this 

permit. 

b. Second Method 9 Observation. Observe exhaust while firing on liquid fuel per 

condition 38.1 within 30 days after the end of a calendar month in which the 

cumulative hours of operation on liquid fuel for the past 12 consecutive months 

exceed 400, except when an 18-minute Method 9 observation has already been 

conducted in accordance with condition 38.1 in the same 12 consecutive month 

period and the emission unit appears to not have excess visible emissions while 

in operation on liquid fuel. 

c. Third Method 9 Observation. Observe exhaust while firing on liquid fuel per 

condition 38.1 within 30 days after the end of a calendar month in which the 

cumulative hours of operation on liquid fuel for the past 12 consecutive month 

period exceed 800. 

d. 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 more than one observation 

is greater than 20 percent. 

39. Visible Emissions Recordkeeping. The Permittee shall keep records in accordance with 

this condition. 

39.1 When conducting the Method 9 observations of condition 38.1 

a. the observer shall record 

(i) the name of the stationary source, emission unit and location, stationary 

source type, observer's name and affiliation, and the date on the Visible 

Emissions Field Data Sheet in Section 14; 
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(ii) the time, estimated distance to the emissions 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 14, 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. 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. calculate and record the highest 18-consecutive-minute average observed. 

40. Visible Emissions Reporting. The Permittee shall report visible emissions as follows: 

40.1 include in each stationary source operating report under condition 83 

a. copies of the observation results (i.e. opacity observations), except for the 

observations the Permittee has already supplied to the Department; and 

b. a summary to include: 

(i) number of days observations were made; 

(ii) highest six-minute average observed; and 

(iii) dates when one or more observed six-minute averages were greater than 

20 percent; 

40.2 a summary of any monitoring or record keeping required under conditions 38 and 39 

that was not done; 

40.3 report under condition 81: 
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a. the results of Method 9 observations that exceed an average 20 percent for any 

six-minute period; and 

b. if any monitoring under condition 38 was not performed when required. 

[18 AAC 50.346(c) & 50.350(g) – (i), 5/3/02] 

41. Particulate Matter Monitoring for Liquid Fuel Fired Heaters. The Permittee shall 

conduct source tests on liquid fuel fired Emission Unit ID(s) 7 and 8, to determine the 

concentration of particulate matter (PM) in the exhaust of an emission unit in accordance 

with the following. 

41.1 Within six months of exceeding the criteria of condition 41.2, either 

a. conduct a PM source test according to requirements set out in Section 10; or 

b. make repairs so that emissions no longer exceed the criteria of condition 41.2; 

to show that emissions are below those criteria, observe emissions as described 

in condition 38.1 under load conditions comparable to those when the criteria 

were exceeded. 

41.2 Conduct the test according to condition 41.1 if 18 consecutive minutes of Method 9 

observations result in an 18-minute average opacity greater than 20 percent. 

41.3 During each one hour PM source test run, observe the exhaust for 18 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. 

41.4 The automatic PM source test requirement in conditions 41.1 and 41.2 is waived for 

an emissions unit if a PM source test on that unit has shown compliance with the PM 

standard during this permit term. 

42. Particulate Matter Reporting for Liquid Fuel Fired Heaters. The Permittee shall 

report for liquid fuel fired Emission Unit ID(s) 7 and 8 as follows: 

42.1 report under condition 81 

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

b. if one of the criteria of condition 41.2 was exceeded and the Permittee did not 

comply with either condition 41.1a or 41.1b; 

42.2 in each stationary source operating report under condition 83, include 

a. the dates, Emission Unit ID(s), and results when an observed 18-minute 

average was greater than an applicable threshold in condition 41.2; 

b. a summary of the results of any PM testing under condition 41; and 
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c. copies of any visible emissions observation results (opacity observations) 

greater than the thresholds of condition 41.2, if they were not already 

submitted. 

43. Particulate Matter Monitoring for Diesel Engines and Liquid Fuel Fired Turbines. 

The Permittee shall conduct source tests on Emission Unit ID(s) 1, 2, 11 through 15, and 

17, to determine the concentration of particulate matter (PM) in the exhaust of an emission 

unit in accordance with the following. 

43.1 Within six months of exceeding the criteria of condition 43.2a or 43.2b, either 

a. conduct a PM source test according to requirements set out in Section 10; or 

b. make repairs so that emissions no longer exceed the criteria of condition 41.2; 

to show that emissions are below those criteria, observe emissions as described 

in condition 38.1 under load conditions comparable to those when the criteria 

were exceeded. 

43.2 Conduct the test according to condition 41.1 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. 

43.3 During each one-hour PM source test run, observe the exhaust for 18 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. 

43.4 The automatic PM source test requirement in conditions 41.1 and 41.2 is waived for 

an emissions unit if a PM source test on that unit has shown compliance with the PM 

standard during this permit term. 

44. Particulate Matter Recordkeeping for Diesel Engines and Liquid Fuel Fired 

Turbines. Within 180 calendar days after the effective date of this permit, the Permittee 

shall record the exhaust stack diameter(s) of Emission Unit ID(s) 1, 2, 11 through 15, and 

17. Report the stack diameter(s) in the next operating report under condition 83. 

45. Particulate Matter Reporting for Diesel Engines and Liquid Fuel Fired Turbines. 

The Permittee shall report for Emission Unit ID(s) 1, 2, 11 through 15, and 17 as follows: 

45.1 Report under condition 81 

a. the results of any PM source test that exceeds the PM emissions limit; or 
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b. if one of the criteria of condition 41.2 was exceeded and the Permittee did not 

comply with either condition 41.1a or 41.1b; 

45.2 Report observations in excess of the threshold of condition 43.2b within 30 days of 

the end of the month in which the observations occur; 

45.3 Include in each stationary source operating report under condition 83, 

a. the dates, Emission Unit ID(s), and results when an observed 18-minute 

average was greater than an applicable threshold in condition 41.2; 

b. a summary of the results of any PM testing under condition 41; and 

c. copies of any visible emissions observation results (opacity observations) 

greater than the thresholds of condition 41.2, if they were not already 

submitted. 

[18 AAC 50.346(c) & 50.350(g) – (i), 5/3/02] 

Flares (Emission Unit ID 18 and 18A) 

46. Visible Emissions Monitoring, Recordkeeping, and Reporting. The Permittee shall 

observe the first six daylight flare events8 occurring during the life of this permit9. 

46.1 Monitor flare events using Method-9 for 18 minutes to obtain 72 individual 15-

second readings. 

46.2 Record the following information for observed events: 

a. the flare(s) Emission Unit ID number; 

b. results of the Method-9 observations; 

c. reason(s) for flaring; 

d. date, beginning and ending time of event; and 

e. cumulative volume of gas flared. 

46.3 Monitoring of a flare event may be postponed for safety or weather reasons, or 

because a qualified observer is not available. Until monitoring has been completed 

on the six flare events described in this condition, the Permittee shall either monitor 

each qualifying flare event or include in the next stationary source operating report 

required by condition 83 an explanation of the reason the event was not monitored. 

 

8

 For purposes of this permit, a “flare event” is flaring of gas for greater than one hour as a result of scheduled 

release operations, i.e. maintenance or well testing activities. It does not include non-scheduled release 

operations, i.e. process upsets, emergency flaring, or de minimis venting of gas incidental to normal operations. 9

 Flare events monitored within 12-months prior to permit effective date may count towards the six-event total. 
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46.4 Attach copies of the records required by condition 46.2 with the stationary source 

operating report required by condition 83. 

46.5 Report under condition 81 whenever the opacity standard in condition 3 is exceeded. 

[18 AAC 50.350(g) – (i), 5/3/02] 
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Section 7. Stationary Source-Wide Requirements 

47. Prohibitions - Significant New Alternatives Policy Programs. The Permittee shall 

comply with the prohibitions set out in 40 C.F.R. 82.174(b) through (d) (Protection of 

Stratospheric Ozone Subpart G - Significant New Alternatives Program) pertaining to 

substitute products for ozone-depleting compounds. Monitor by certifying annually that 

the Permittee complies with these prohibitions. 

[18 AAC 50.040(d) and 50.350(d)(1), 1/18/97] 

[40 C.F.R. 82.174(b) - (d), 1/13/95] 

48. Prohibitions - Halon Emissions Reduction. The Permittee shall comply with the 

prohibitions set out in 40 C.F.R. 82.270(b) through (f) (Protection of Protection of 

Stratospheric Ozone Subpart H - Halon Emissions Reduction). Monitor by certifying 

annually that the Permittee complies with these prohibitions. 

[18 AAC 50.040(d) and 50.350(d)(1), 1/18/97] 

[40 C.F.R. 82.270(b) - (f), 3/5/98] 

49. Emission Unit Aggregation. The Permittee shall aggregate potential emissions from 

CFP, B-pad, and E-pad at the Milne Point Unit for the purpose of determining applicability 

with the modification requirements of 18 AAC 50.300(h)(3). This condition is not 

federally enforceable. 

[18 AAC 50.990(37), 1/18/97] 

[18 AAC 50.910, 1/18/97] 

50. Notification Requirements. Notwithstanding the regulations set forth in 

18 AAC 50.300(h), the Permittee shall notify the Department, in accordance with 

condition 51, prior to:

[Construction Permit No. 0073-AC023, 7/13/01]

50.1 installing a stationary source at the stationary source that is not listed in Table 1of 

this permit; 

50.2 making a change to an emission unit listed in Table 1 that would cause it to deviate 

from the description of it provided in Table 1; or 

50.3 making a change to the emission characteristics of an emission unit listed in Table 1, 

including adding waste heat recovery, in a manner that would increase the ambient 

air quality impact. 

51. Notification Procedures. The Permittee shall use the following procedures when 

notifying the Department pursuant to condition 50: 

[Construction Permit No. 0073-AC023, 7/13/01] 

51.1 For changes described by 18 AAC 50.370(a), notify the Department in accordance 

with 18 AAC 50.370(b). The Permittee may implement the changes in accordance 

with 18 AAC 50.370(c). 

51.2 For all other changes, 
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a. ask the Department if additional ambient impact assessment modeling is 

warranted for the proposed change; 

b. within 60 days of receiving written Department notice that modeling is 

warranted, prepare and submit to the Department an ambient impact assessment 

for the specified air pollutant and averaging period; and 

c. do not make the change until the Department concurs that the change will not 

interfere with attainment or maintenance of ambient air quality standards and 

maximum allowable ambient concentrations. 
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Section 8. Insignificant Emission Units 

This section contains the requirements that the Permittee identified under 18 AAC 50.335(q)(2) 

as applicable to insignificant emission units at the stationary source. This section also specifies 

the testing, monitoring, recordkeeping, and reporting for insignificant emission units that the 

Department finds necessary to ensure compliance with the applicable requirements. Insignificant 

emission units are not exempted from any air quality control requirement or federally 

enforceable requirement. 

As set out in 18 AAC 50.350(m), the shield of AS 46.14.290 does not apply to these emission 

units. 

52. For emission units at the stationary source that are insignificant as defined in 18 AAC 

50.335(q)-(v) that are not listed in this permit, the following apply: 

52.1 The Permittee shall submit the compliance certifications of condition 84 based on 

reasonable inquiry; 

52.2 The Permittee shall comply with the requirements of condition 64; 

52.3 The Permittee shall report in the stationary source operating report required by 

condition 83 if an emission unit listed in this condition 52, because of actual 

emissions less than the thresholds of 18 AAC 50.335(r), has actual emissions greater 

than any of those thresholds set out in 18 AAC 50.335(r). 

52.4 No other monitoring, recordkeeping or reporting is required. 

[18 AAC 50.346(b)(1), 5/3/02] 

53. 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 any of the following: 

53.1 more than 20% for more than three minutes in any one hour10, 

[18 AAC 50.055(a)(1), 1/18/97, 40 CFR 52.70, 11/18/98] 

53.2 more than 20% averaged over any six consecutive minutes. 

[18 AAC 50.055(a)(1), 5/3/02] 

54. 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), 1/18/97] 

55. 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), 1/18/97] 

 

10 See Footnote 1. 
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Section 9. Generally Applicable Requirements 

56. NESHAPs Subpart A, Applicability Determination. The Permittee shall determine rule 

applicability and designation of affected emission units under National Emission Standards 

for Hazardous Air Pollutants (NESHAPs) for Source Categories (40 CFR 63) in 

accordance with the procedures described in 40 CFR 63.1(b). 

56.1 NESHAPS Subpart A, Recordkeeping. The Permittee shall maintain records in 

accordance with §63.10(b)(3). 

[40 C.F.R. 63.1(b) & C.F.R. 63.10(b)(3), 7/1/01] 

[18 AAC 50.040(c)(1)(A) & 50.040(c(1)(E), 7/2/00; 18 AAC 50.350(h), 1/18/97] 

57. Asbestos NESHAP. The Permittee shall comply with the requirements set forth in 

40 C.F.R. 61.145 and 61.150 (Subpart M) and the applicable sections set forth in 

40 C.F.R. 61, Subpart A and Appendix A. 

[18 AAC 50.040(b)(3) & 50.350(d)(1), 1/18/97] 

[40 C.F.R. 61, Subparts A & M, and Appendix A, 12/19/96] 

58. Refrigerant Recycling and Disposal. The Permittee shall comply with the applicable 

standards for recycling and emission reduction of refrigerants set forth in 40 C.F.R. 82, 

Subpart F. Applicable requirements include 40 CFR 82.154, 82.156, 82.161, 82.162, and 

82.166. 

[18 AAC 50.040(d) & 50.350(d)(1), 1/18/97] 

[40 C.F.R. 82, Subpart F, 7/1/97] 

59. Good Air Pollution Control Practice. The Permittee shall do the following for Emission 

Unit ID(s) 5 through 25: 

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; 

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

procedures. 

[18 AAC 50.030 & 50.346(b)(2), 5/3/02 & 18 AAC 50.350(f)(2) & (3), 1/18/97] 

60. 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), 1/18/97] 

61. Reasonable Precautions to Prevent Fugitive Dust. The Permittee shall take reasonable 

precautions to prevent particulate matter from being emitted into the ambient air when 

causing or permitting bulk materials to be handled, transported, or stored, or when 

engaging in an industrial activity or construction project. Monitoring shall consist of an 

annual certification that reasonable precautions were taken. 
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[18 AAC 50.346(c), 5/3/02; 18 AAC 50.045(d) & 50.335(g), 1/18/97 & 18 AAC 50.040(e), 7/2/00] 

62. 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, unless approved in 

writing by the Department. Monitoring shall consist of an annual certification that the 

Permittee does not conduct stack injection at the stationary source. 

[18 AAC 50.055(g), 1/18/97] 

63. Open Burning. The Permittee shall conduct any open burning at the stationary source in 

accordance with the requirements of 18 AAC 50.065. Monitoring shall consist of an 

annual certification that any open burning complied with 18 AAC 50.065. 

[18 AAC 50.040(e), 7/21/01, 18 AAC 50.065, 7/21/01, 18 AAC 50.350(d)(1), 1/18/97] 

64. 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 50.346(a)(2), 5/3/02; 18 AAC 50.110, 5/26/72; 18 AAC 50.040(e), 7/2/00] 

64.1 If emissions present a potential threat to human health or safety, the Permittee shall 

report any such emissions according to condition 81. 

64.2 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 64. 

64.3 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 64; or 

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

64. 

64.4 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 64; and 

d. any corrective actions taken or planned for complaints attributable to emissions 

from the stationary source. 
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64.5 With each stationary source operating report required under condition 83, 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. 

64.6 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. 

[18 AAC 50.346(a)(2) & 50.350(g) - (i), 5/3/02] 

65. Technology-Based Emission Standard. If an unavoidable emergency, malfunction, or 

non-routine repair, as defined in 18 AAC 50.235, causes emissions in excess of a 

technology-based emission standard11, the Permittee shall take all reasonable steps to 

minimize levels of emissions that exceed the standard. Excess emissions reporting under 

condition 81 requires information on the steps taken to minimize emissions. The report 

required under condition 81 is adequate monitoring for compliance under this condition. 

[18 AAC 50.235(a) & 50.350(f)(3), 1/18/97] 

66. Permit Renewal. To renew this permit, the Permittee shall submit an application under 

18 AAC 50.335 no sooner than November 13, 2006 and no later than November 13, 2007.

[18 AAC 50.335(a), 1/18/97] 

 

11 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 

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. [18 AAC 50.990(91)] 
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Section 10. General Source Testing and Monitoring Requirements 

67. 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), 1/18/97 & 18 AAC 50.345(a) & (k), 5/3/02] 

68. Operating Conditions. Unless otherwise specified by an applicable requirement or test 

method, the Permittee shall conduct source testing 

[18 AAC 50.220(b) & 50.350(g), 1/18/97] 

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

68.2 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. 

69. Reference Test Methods. The Permittee shall use the following as reference test methods 

when conducting source testing for compliance with this permit: 

69.1 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) & 50.350(g), 1/18/97 & 18 AAC 50.040(a), 8/15/02] 

[40 C.F.R. 60, 7/1/01] 

69.2 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), 8/15/02; 50.220(c)(1)(B) & 50.350(g), 1/18/97] 

[40 C.F.R. 61, 7/1/01] 

69.3 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), 8/15/02, 18 AAC 50.220(c)(1)(C) & 50.350(g), 1/18/97] 

[40 C.F.R. 63, 7/1/01] 

69.4 Source testing for reduction in visibility through the exhaust effluent must be 

conducted in accordance with the procedures set out in Reference Method 9. 

[18 AAC 50.030, 5/3/02, 18 AAC 50.220(c)(1)(D) & 50.350(g), 1/18/97] 

69.5 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)(4), 8/15/02 & 18 AAC 50.220(c)(1)(E) & 50.350(g), 1/18/97] 

[40 C.F.R. 60, Appendix A, 7/1/01] 
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69.6 Source testing for emissions of PM-10 must be conducted in accordance with the 

procedures specified in 40 C.F.R. 51, Appendix M, Method 201. 

[18 AAC 50.035(b)(2), 7/2/00; 18 AAC 50.220(c)(1)(F) & 50.350(g), 1/18/97] 

[40 C.F.R. 51, Appendix M, 7/1/01] 

69.7 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)(19), 8/15/02 & 18 AAC 50.220(c)(2) & 50.350(g), 1/18/97] 

 [40 C.F.R. 63, Appendix A, Method 301, 4/5/02] 

70. 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 source 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), 18 AAC 50.350(g), 1/18/97 & 18 AAC 50.990(88), 5/3/02] 

71. Test Exemption. The Permittee is not required to comply with conditions 73, 74 and 75 

when the exhaust is observed for visible emissions. 

[18 AAC 50.345(a), 5/3/02] 

72. 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), 5/3/02] 

73. Test Plans. Except as provided in condition 71, 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 67 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 done 

without resubmitting the plan. 

[18 AAC 50.345(a) & (m), 5/3/02] 

74. Test Notification. Except as provided in condition 71, 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), 5/3/02] 
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75. Test Reports. Except as provided in condition 71, 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 

certify the results in the manner set out in condition 77. 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), 5/3/02] 

76. Particulate Matter Calculations. In source testing for compliance with the particulate 

matter standards in conditions 4 and 54, the three-hour average is determined using the 

average of three one-hour test runs. 

[18 AAC 50.220(f) & 50.350(g), 1/18/97] 
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Section 11. General Recordkeeping, Reporting, and Compliance Certification 

Requirements 

77. Certification. The Permittee shall certify all reports, compliance certifications, or other 

documents 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. When certifying a compliance certification, 

the official’s signature must be notarized. 

[18 AAC 50.205 and 50.350(b)(3) & (j), 1/18/97; and 18 AAC 50.345(a) & (j), 5/3/02] 

78. Submittals. Unless otherwise directed by the Department or this permit, the Permittee 

shall send reports, compliance certifications, and other documents required by this permit 

to ADEC, Air Permits Program, 610 University Ave., Fairbanks, AK 99709-3643, ATTN: 

Compliance Technician. 

[18 AAC 50.350(i), 1/18/97] 

79. 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 50.200 & 50.350(b)(3), 1/18/97; and 18 AAC 50.345(a) & (i) & 50.350(g) – (i), 5/3/02] 

80. Recordkeeping Requirements. The Permittee shall keep all records required by this 

permit for at least five years after the date of collection, including: 

[18 ACC 50.350(h), 5/3/02] 

[40 C.F.R. 60.7(f), Subpart A, 7/1/01] 

80.1 copies of all reports and certifications submitted pursuant to this section of the 

permit; and 

80.2 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. sampling dates and times of sampling or measurements; 

c. the operating conditions that existed at the time of sampling or measurement; 

d. the date analyses were performed; 
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Revision 1: May 25, 2004 

 

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e. the location where samples were taken; 

f. the company or entity that performed the sampling and analyses; 

g. the analytical techniques or methods used in the analyses; and 

h. the results of the analyses. 

81. Excess Emissions and Permit Deviation Reports. 

81.1 Except as provided in condition 64, 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 nonroutine 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 or is discovered, except as provided in conditions 81.1c(ii) and 

81.1c(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 81.1c(i); and 

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

permit. 

81.2 When reporting excess emissions, the Permittee must report using either the 

Department’s on-line form, which can be found at 

www.dec.state.ak.us/awq/excess/report.asp, or, if the Permittee prefers, the form 

contained in Section 16 of this permit. The Permittee must provide all information 

called for by the form that is used. 

81.3 When reporting a permit deviation, the Permittee must report using the form 

contained in Section 16 of this permit. The Permittee must provide all information 

called for by the form. 
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81.4 If requested by the Department, the Permittee shall provide a more detailed written 

report as requested to follow up an excess emissions report. 

[18 AAC 50.235(a)(2), 50.240(c), & 50.350(i), 1/18/97; and 18 AAC 50.346(a)(3), 5/3/02]

82. NSPS and NESHAP Reports. The Permittee shall: 

[18 AAC 50.040, 8/15/02; & 50.350(i)(2), 1/18/97; and 40 C.F.R. 60 & 61, 7/1/01] 

82.1 attach to the stationary source operating report required by condition 83, copies of 

any NSPS and NESHAPs reports submitted to the U.S. Environmental Protection 

Agency (EPA) Region 10 unless copies have already been provided to the 

Department at the time submitted to EPA, and 

82.2 upon request by the Department provide a copy of any EPA-granted waiver of the 

federal emission standards, record keeping, monitoring, performance testing, or 

reporting requirements, or approved custom monitoring schedules. 

83. Operating Reports. During the life of this permit, the Permittee shall submit to the 

Department an original and two copies of an operating report by April 30 for the period 

January 1 to March 31, by July 30 for the period April 1 to June 30, by October 30 for the 

period July 1 to September 30, and by February 14 for the period October 1 to December 

31 of the previous year. 

83.1 The operating report must include all information required to be in operating reports 

by other conditions of this permit. 

83.2 If excess emissions or permit deviations that occurred during the reporting period are 

not reported under condition 83.1, 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 81 the Permittee may cite the date or dates of those reports. 
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83.3 The operating report must include a listing of emissions monitored under 

condition 38 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 that additional monitoring or testing was triggered; 

b. the equipment involved; 

c. the permit condition affected; and 

d. the monitoring result which triggered the additional monitoring. 

[18 AAC 50.346(b)(3), 5/3/02; 18 AAC 50.350(d)(4), 6/21/98; and 18 AAC 50.350(f)(3) & (i), 1/18/97] 

84. Annual Compliance Certification. Each year by March 31, and for reporting periods 

following the effective date of this permit the Permittee shall compile and submit to the 

Department an original and two copies of an annual compliance certification report as 

follows: 

[18 AAC 50.350(j), 1/18/97] 

84.1 For each permit term and condition set forth in Section 4 through Section 11, 

including terms and conditions for monitoring, reporting, and recordkeeping: 

[18 AAC 50.350(d)(4), 6/21/98] 

a. certify the compliance status over the preceding calendar year consistent with 

the monitoring required by this permit; 

b. state whether compliance is intermittent or continuous; 

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

d. notarize the responsible official’s signature. 

[18 AAC 50.205, 1/18/97 & 50.345(a) & (j), 5/3/02] 

84.2 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 50.350(j), 1/18/97] 
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Section 12. Standard Conditions Not Otherwise Included in the Permit 

85. The Permittee must comply with each permit term and condition. Noncompliance with a 

permit term or condition constitutes a violation of AS 46.14, 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 

85.1 an enforcement action; 

85.2 permit termination, revocation and reissuance, or modification in accordance with 

AS 46.14.280; or 

85.3 denial of an operating-permit renewal application. 

[18 AAC 50.350(b)(3), 1/18/97 & 18 AAC 50.345(a) & (c), 5/3/02] 

86. 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 50.350(b)(3), 1/18/97 & 18 AAC 50.345(a) & (d), 5/3/02] 

87. 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 50.350(b)(3), 1/18/97 & 18 AAC 50.345(a) & (e), 5/3/02] 

88. Compliance with permit terms and conditions is considered to be compliance with those 

requirements that are 

88.1 included and specifically identified in the permit; or 

88.2 determined in writing in the permit to be inapplicable. 

[18 AAC 50.350(b)(3), 1/18/97 & 18 AAC 50.345(a) & (b), 5/3/02] 

89. The permit may be modified, reopened, revoked and reissued, or terminated for cause. A 

request by the Permittee for modification, revocation and reissuance, or termination or a 

notification of planned changes or anticipated noncompliance does not stay any permit 

condition. 

[18 AAC 50.350(b)(3), 1/18/97 & 18 AAC 50.345(a) & (f), 5/3/02] 

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

[18 AAC 50.350(b)(3), 1/18/97 & 18 AAC 50.345(a) & (g), 5/3/02] 

91. 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 

91.1 enter upon the premises where an emission unit subject to the permit is located or 

where records required by the permit are kept; 
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91.2 have access to and copy any records required by the permit; 

91.3 inspect any stationary source, equipment, practices, or operations regulated by or 

referenced in the permit; and 

91.4 sample or monitor substances or parameters to assure compliance with the permit or 

other applicable requirements. 

[18 AAC 50.350(b)(3), 1/18/97 & 18 AAC 50.345(a) & (h), 5/3/02] 
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Section 13. Permit As Shield from Inapplicable Requirements 

In accordance with AS 46.14.290, and based on information supplied in the stationary source 

application, this section of the permit contains the requirements determined by the Department 

not to be applicable to the Milne Point Production Facility. 

Table 6 identifies the emission units that are not subject to the specified requirements at the time 

of permit issuance. Some of the requirements listed below may become applicable during the 

permit term due to an invoking event, even though the requirement is deemed inapplicable at the 

time of permit issuance. 

92. If any of the requirements listed in Table 6 become applicable during the permit term, the 

Permittee shall comply with such requirements on a timely basis. The Permittee shall also 

provide appropriate notification to EPA, and apply for a construction permit or an 

operating permit revision, if necessary. 

Table 6 - Permit Shields Granted. 

Non Applicable Requirements Reason Non-Applicable 

All Gas-Fired Heaters 

40 CFR 60 Subpart D Heat input capacities below threshold (250 MMBtu/hr); and units 

not classified as Fossil-Fuel-Fired Steam Generators, as defined 

in subpart 

40 CFR 60 Subpart Da Heat input capacities below threshold (250 MMBtu/hr); and units 

not classified as Fossil-Fuel-Fired Steam Generators, as defined 

in subpart 

40 CFR 60 Subpart Db Heat input capacities below threshold (100 MMBtu/hr); and 

commenced prior to effective date of subpart 

Heaters: H-4510A, H-4510B, H-5701A, H-5701B, H-2001A, and H-2001B 

40 CFR 60 Subpart Dc Commenced construction prior to effective date of subpart 

(6/9/89) 

Heaters: H-5302A and H-5302B 

40 CFR 60 Subpart A: §60.7(a)(1), (2), 

& (3) 

40 CFR 60 Subpart Dc: §60.48c(a)(1) 

(Initial Notification Only) 

Obsolete requirements – completed as required. 

40 CFR 60 Subpart A: §60.7(a)(4) This requirement only applies to “existing facilities, “ as defined 

in 40 CFR 62. 

40 CFR 60 Subpart A: §60.7(c)&(d) The provisions of 60.7(c)&(d) apply only to New Source 

Performance Standards which require the installation of a 

continuous monitoring system (CMS) or monitoring device, as 

defined in 60.2; BPX is not required to install a CMS or 

monitoring device per Subpart Dc 

40 CFR 60 Subpart A: §60.8 

40 CFR 60 Subpart Dc: §§60.42c, 

60.43c, 60.44c, 60.45c, 60.46c, 60.47c, 

60.48c(a)(4), (b) - (f) & (h) 

Standards for SO2 and PM and related performance test, 

monitoring, and reporting requirements not applicable for affected 

stationary source fired on fuel gas 

40 CFR 60 Subpart Dc: §60.48c(a)(2) – 

(3) 

Stationary source is not subject to any requirements that limit the 

annual capacity factor for any fuel or mixture of fuels – stationary 

source fires only fuel gas. 

All Storage Tanks 

40 CFR 60 Subpart K Commenced construction after effective date(s) of subpart 

(5/19/78) 
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Non Applicable Requirements Reason Non-Applicable 

40 CFR 60 Subpart Ka Commenced construction after effective date(s) of subpart 

(7/23/84) 

Storage Tanks #1 (Produced Water Surge Tank), T-6001, and T-6101B 

40 CFR 60 Subpart Kb Contents stored prior to custody transfer, therefore vessel is 

exempt from the subpart 

Storage Tanks: T-6101A and T-2002 

40 CFR 60 Subpart A 

40 CFR 60 Subpart Kb: §§60.112b, 

60.113b, 60.114b, 60.115b, 60.116b(c)-

(g) 

T-6101A: Except as specified in paragraphs (a) and (b) of 

60.116b, vessels with a capacity of > or = 151 cubic meters storing 

a liquid with a maximum true vapor pressure < 3.5 kPa (0.5 psia) 

are exempt from General Provisions – Subpart A, and from the 

provisions of Subpart Kb 

T-2002: Except as specified in paragraphs (a) and (b) of 60.116b, 

vessels with a capacity < 75 cubic meters are exempt from General 

Provisions – Subpart A, and from the provisions of Subpart Kb 

Turbines: PU-0701 and PU-0801 

40 CFR 60 Subpart GG: §60.332(a)(1) Standard only applies to Electric Utility Stationary Gas Turbines, 

as defined in subpart – emission unit is not an Electric Utility 

Stationary Gas Turbine as defined in Subpart GG 

40 CFR 60 Subpart GG: §60.332(a)(2) 

when firing liquid (emergency) fuel 

Standard does not apply when firing emergency fuel as defined in 

subpart. 

40 CFR 60 Subpart GG: §§60.334(b), 

60.335(a) for fuel-bound Nitrogen 

testing of fuel gas only 

EPA Region X waived fuel-bound nitrogen monitoring for NSPS 

affected stationary gas turbines operated by BPXA at Milne Point 

(ref. correspondence dated August 28, 2002;). No shield is 

provided for sulfur monitoring requirements in these subparts. 

40 CFR 60 Subpart A: §60.7(a)(1), (2), 

& (3) 

(Initial Notification Only) 

Obsolete requirements – completed as required. 

40 CFR 60 Subpart A: §60.7(a)(4) This requirement only applies to “existing facilities”, as defined in 

40 CFR 60.2 

40 CFR 60 Subpart A: §60.8(a) 

40 CFR 60 Subpart GG: §§60.335(b), 

(c)(1), (c)(3) 

(Initial Performance Test Only) 

Obsolete requirements – completed as required. 

All Flares 

40 CFR 60 Subpart A: §60.18 These flares are not control devices used to comply with 

applicable Subparts of 40 CFR 60 and 40 CFR 61 

Stationary source-Wide 

40 CFR 60 Subpart J, GGG, QQQ Stationary source does not meet the definition for a petroleum 

refinery 

40 CFR 60 Subpart KKK Stationary source is not a natural gas processing plant as defined 

in subpart 

40 CFR 60 Subpart LLL Stationary source does not operate natural gas sweetening unit(s) 

40 CFR 61 Subpart A Requirements only apply to sources subject to any provisions of 

40 CFR 61 

40 CFR 61 Subpart J No process components in benzene service, as defined by subpart 

(10% benzene by weight) 

40 CFR 61 Subpart M: §61.142 Stationary source is not an Asbestos Mill 

40 CFR 61 Subpart M: §61.143 Stationary source roadways not exposed to asbestos tailings or 

asbestos containing waste 

40 CFR 61 Subpart M: §61.144 Stationary source does not engage in any manufacturing 

operations using commercial asbestos 

40 CFR 61 Subpart M: §61.146 Stationary source does not spray apply asbestos containing 

materials 
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Revision 1: May 25, 2004 

 

Page 54 of 61 

Non Applicable Requirements Reason Non-Applicable 

40 CFR 61 Subpart M: §61.147 Stationary source does not engage in any fabricating operations 

using commercial asbestos 

40 CFR 61 Subpart M: §61.148 Stationary source does not install or reinstall, on any stationary 

source component, insulation material containing commercial 

asbestos 

40 CFR 61 Subpart M: §61.149 Applies to only those facilities subject to 61.142 

40 CFR 61 Subpart M: §61.151 Applies to only those facilities subject to 61.142, 61.144, or 

61.147 

40 CFR 61 Subpart M: §61.152 Stationary source does not use air cleaning equipment 

40 CFR 61 Subpart M: §61.153 No reporting requirements apply for sources subject to 61.145 

40 CFR 61 Subpart M: §61.154 Stationary source is not an active waste disposal site and does not 

receive asbestos containing waste material 

40 CFR 61 Subpart M: §61.155 Stationary source does not process regulated asbestos containing 

material (RACM) 

Activities subject to 40 CFR 61, Subpart M §61.145 

40 CFR 61 Subpart A: §§61.05(a), 

61.07, 61.09 

Owners or operators of demolition and renovation operation are 

exempt from the requirements of 61.05(a), 61.07, and 61.09 

40 CFR 61 Subpart A: §61.10 Demolition and renovation operations exempt from 61.10(a) 

40 CFR 61 Subpart A: §§61.13, 61.14 Emission tests or monitoring is not required under the standards 

for demolition and renovation 

Stationary source-Wide 

40 CFR 61 Subpart V No process components in volatile hazardous air pollutant 

(VHAP) service, as defined by subpart (> or = 10 % VHAP by 

weight) 

40 CFR 61 Subpart Y Stationary source does not operate storage vessels in benzene 

service 

40 CFR 61 Subpart BB Stationary source does not conduct benzene transfer operations 

40 CFR 61 Subpart FF Stationary source does not conduct benzene waste operations 

40 CFR 63 Subpart T Stationary source does not operate halogenated solvent cleaning 

machines 

40 CFR 63 Subpart CC Stationary source does not meet the definition for a petroleum 

refinery 

All Storage Tanks 

40 CFR 63 Subpart OO Provisions only apply to tanks affected by 40 CFR 60, 61, or 63 

that specifically reference 40 CFR 63 Subpart OO

40 CFR 63 Subpart SS Provisions only apply to tanks affected by 40 CFR 60, 61, or 63 

that specifically reference 40 CFR 63 Subpart SS

Drain Systems 

40 CFR 63 Subpart RR Provisions only apply to drain systems affected by 40 CFR 60, 61, 

or 63 that specifically reference 40 CFR 63 Subpart RR 

Stationary source-Wide 

40 CFR 63 Subpart VV Provisions only apply to oil-water separators and organic-water 

separators affected by 40 CFR 60, 61, or 63 that specifically 

reference 40 CFR 63 Subpart VV 

40 CFR 63 Subpart HH Stationary source exempt from subpart because it exclusively 

processes, stores, or transfers “black oil” and stationary source is 

not a major source of HAPs. 

40 CFR 63 Subpart HHH Stationary source does not transmit or store natural gas prior to 

entering the pipeline to a local distribution company or to a final 

end user and stationary source is not a major source of HAPs. 

40 CFR 63 Subpart EEEE Stationary source is not a major source of HAPs. 

40 CFR 63 Subpart A (except for 

§63.1(b) & §63.10(b)(3) 

Requirements only apply to emission units subject to any 

provision of 40 CFR 63 – this stationary source is not subject to 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 55 of 61 

Non Applicable Requirements Reason Non-Applicable 

40 CFR 63, Subpart A except for the requirement to determine 

rule applicability in 40 C.F.R. 63.1(b) and to keep records of rule 

applicability determination in 40 C.F.R. 63.10(b)(3). 

Turbines: PU-0701 and PU-0801 

40 C.F.R. 64 - Compliance Assurance 

Monitoring 

The parametric correlations for PU-0701 and PU-0801, along with 

the associated continuous process monitors required by the Title V 

operating permit for these units, qualify as a "continuous 

compliance determination method" as defined in 40 C.F.R. 64.1. 

Therefore these units are exempt from 40 C.F.R. 64 per 

§64.2(b)(1)(vi). 

Tank: T-2002 and Glycol Dehydration Unit (Emission Unit ID 25) 

40 C.F.R. 64 - Compliance Assurance 

Monitoring 

These units do not have pre-control device emissions of an 

applicable regulated air pollutant equal to or greater than 100 tpy 

(criteria pollutants), 10 tpy any individual hazardous air pollutant 

(HAP), or 25 tpy all HAP combined. 

All Units except PU-0701, PU-0801, T-2002, and Glycol Dehydration Unit (Emission Unit ID 25)

40 C.F.R. 64 - Compliance Assurance 

Monitoring 

These units do not use a control device to achieve compliance with 

any emission limitation or standard. 

Stationary source-Wide 

40 C.F.R. 68 - Risk Management 

Programs 

"Naturally occurring hydrocarbon mixtures: (crude oil, 

condensate, natural gas and produced water) prior to entry into a 

petroleum refining process unit (NAICS code 32411) or a natural 

gas processing plant (NAICS code 211112) are exempt from the 

threshold determination. (See final Rule exempting from 

threshold determination regulated flammable substances in 

naturally occurring hydrocarbons mixtures prior to initial 

processing, 63 FR 640 [January 6, 1998]). Less than 10,000 lbs. 

of other mixtures containing regulated flammable substances that 

meet the criteria for an NFPA rating of 4 for flammability are 

stored at the stationary source. Therefore, CFP, B-Pad, and E-Pad, 

a crude petroleum and natural gas production stationary source, 

(NAICS code 211111) does not process or store regulated 

flammable or toxic substances in excess of threshold quantities. 

40 CFR 82 Subpart A: §82.1 Stationary source does not produce, transform, destroy, import or 

export Class I or Group I or II substances or products 

40 CFR 82 Subpart B: §82.30 Stationary source does not service motor vehicles air conditioners 

40 CFR 82 Subpart C: §82.60 Stationary source is not the ultimate consumer and not a 

manufacturer or distributor of Class I and II products or 

substances 

40 CFR 82 Subpart D: §82.80 Subpart applies only to Federal departments, agencies, and 

instrumentalities 

40 CFR 82 Subpart E: §82.100 Stationary source is not the ultimate consumer and not a 

manufacturer or distributor of Class I and II products or 

substances 

40 CFR 82 Subpart F: §82.158 Stationary source does not manufacture or import recovery and 

recycling equipment. 

40 CFR 82 Subpart F: §82.160 Stationary source does not contract equipment testing organization 

to certify recovery and recycling equipment 

40 CFR 82 Subpart F: §82.164 Stationary source does not sell reclaimed refrigerant 

40 CFR 82 Subpart F: Appendix C Stationary source is not a third party entity that certifies recovery 

equipment 

40 CFR 82 Subpart F: Appendix D Stationary source does not have technician certification program 

40 CFR 82 Subpart G: §82.174(a) Stationary source does not manufacture substitute chemicals or 

products for ozone-depleting compounds. 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 56 of 61 

Non Applicable Requirements Reason Non-Applicable 

40 CFR 82 Subpart H: §82.270(a) Stationary source does not manufacture halon. 

Non-road Engine: PU-4703 

18 AAC 50.055 The limits of 18 AAC 50.055 do not apply to non-road engines. 

Stationary source-Wide 

18 AAC 50.201 Requirement is not applicable until such time as the Department 

requests an ambient air quality investigation 

[18 AAC 50.350(l), 1/18/97] 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 57 of 61 

Section 14. Visible Emissions Forms 

Visible Emissions Field Data Sheet 

Certified Observer: _________________________

Company: 

Location: 

Test No.: Date: 

Source: 

Operating Rate: 

 

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 

 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 58 of 61 

Visible Emissions Observation Record 

Page ___ of ___ 

Company _________________ 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

Data Reduction: 

Duration of Observation Period (minutes) ________________ 

Number of Observations _________________ 

Number of Observations exceeding 20% __________________ 

Average Opacity Summary 

Set Time Opacity 

Number Start—End Sum Average 

 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 59 of 61 

Section 15. SO2 Material Balance Calculation 

If a fuel shipment contains more than 0.75 percent sulfur 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 = 20.9 – [vol%dryO2, exhaust] = 20.9 - ______ = ______ 

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 XI.2. 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 analysis under 40 C.F.R. 60, 

Appendix A-2, Method 3, adopted by reference in 18 AAC 50.040(a), 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), 5/3/02] 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 60 of 61 

Section 16. ADEC Notification Form

Fax this form to: (907) 269-7508 Telephone: (907) 269-8888 

BP Exploration (Alaska) Inc..

Company Name 

Milne Point Production Facility

Facility Name 

Reason for notification: 

 Excess Emissions T Other Deviation from Permit Condition 

If you checked this box If you checked this box 

Fill out section 1 fill out section 2 

When did you discover the Excess Emissions or Other Deviation: 

Date:__/__/__ Time:__:__ 

Section 1. Excess Emissions 

(a) Event Information (Use 24-hour clock): 

START Time: END Time: Duration

(hr:min): 

Date: : : : 

Date: : : : 

Total: : 

(b) Cause of Event (Check all that apply): 

T START UP T UPSET CONDITION T CONTROL EQUIPMENT 

T SHUT DOWN T SCHEDULED MAINTENANCE T OTHER ____________________ 

Attach a detailed description of what happened, including the parameters or operating conditions 

exceeded. 

(c) Sources Involved: 

Identify each emission source involved in the event, using the same identification number and 

name as in the permit. List any control device or monitoring system affected by the event. Attach 

additional sheets as necessary. 

Source ID No. Source Name Description Control Device 

 

 

(d) Emission Limit Potentially Exceeded 

Identify each emission standard potentially exceeded during the event. Attach a list of ALL 

known or suspected injuries or health impacts. Identify what observation or data prompted this 

report. Attach additional sheets as necessary. 

Permit Condition Limit Emissions Observed 

 

 

(e) Excess Emission Reduction: 

Attach a description of the measures taken to minimize and/or control emissions during the event. 

(f) Corrective Actions: 
Permit No. 200TVP01 Issued: April 14, 2003 

Milne Point Production Facility Expires: May 13, 2008 

Revision 1: May 25, 2004 

 

Page 61 of 61 

Attach a description of corrective actions taken to restore the system to normal operation and to 

minimize or eliminate chances of a recurrence. 

(g) Unavoidable Emissions: 

Do you intend to assert that these excess emissions were unavoidable? 

T YES T NO 

Do you intend to assert the affirmative defense of 18 AAC 50.235? 

T YES T NO 

Section 2. Other Permit Deviations 

(a) Sources Involved: 

Identify each emission source involved in the event, using the same identification number and 

name as in the permit. List any control device or monitoring system affected by the event. Attach 

additional sheets as necessary. 

Source ID No. Source Name Description Control Device 

 

 

 

(b) Permit Condition Deviation: 

Identify each permit condition deviation or potential deviation. Attach additional sheets as 

necessary. 

Permit Condition Potential Deviation 

 ___________________________________ ______________________________________ 

 ___________________________________ ______________________________________ 

 ___________________________________ ______________________________________ 

(c) Corrective Actions: 

Attach a description of actions taken to correct the deviation or potential deviation and to prevent 

recurrence. 

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: Signature: Date: 
Milne Point Production Facility 

C:\Documents and Settings\pwright\Desktop\bpxampufinal\BPXA MPU FinalPermit&SOB-Revision1.doc 

Alaska Department of Environmental Conservation 

Air Permits Program 

April 14, 2003 

BP Exploration (Alaska) Inc. 

Milne Point Production Facility 

STATEMENT OF BASIS 

of the terms and conditions for 

Permit No. 200TVP01 

Prepared by Sally Ryan and Robert Dolan 

Revision 1 – William Ashton 

May 25, 2004 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

 

Page 2 of 43 

INTRODUCTION 

This document sets forth the legal and factual basis for the terms and conditions of Operating 

Permit No. 200TVP01, as amended through Revision 1. 

STATIONARY SOURCE IDENTIFICATION 

Section 1 of Operating Permit No. 200TVP01, Revision 1 contains information on the stationary 

source as provided in the Title V permit application and subsequent submittals and as revised in 

Construction Permit No. 0073-AC023 and 200CP01. 

The Milne Point Production Facility is an oil and gas exploration and production operation. The 

SIC code is 1311. The stationary source is owned and operated by BP Exploration (Alaska) Inc., 

who is also the Permittee for this permit. Fuel gas, crude oil, and water are extracted from the 

subsurface of well pads. This mixture of fluids is transported by pipeline to the Central Facility 

Pad (CFP) where the gas, crude, and water are separated. Some of the fuel gas is used as a fuel 

in the combustion equipment at the CFP and well pads; the remainder is compressed and reinjected back into the reservoir. Separated produced water is also re-injected into the reservoir. 

Well work that involves the use of rotary drill rigs and associated engines, boilers, heaters, 

camps and camp equipment, pits and tanks is performed periodically at B-Pad and E-Pad. Such 

well work is of short duration and performed according to dynamic schedules. 

EMISSION UNIT INVENTORY AND DESCRIPTION 

Table 1 of Operating Permit No. 200TVP01, Revision 1 contains information on the emission 

units at the stationary source as provided in the Title V permit application and subsequent 

submittals and as revised in Construction Permit No. 0073-AC023, and 200CP02, with the 

following exceptions: 

• The ratings for Emission Unit ID(s) 9 and 10 changed in 2001 when low NOX burners were 

added. 

• The Title V application indicated that there are two Produced Water Surge Tanks. The 

Department revised this to one based on a comment by BPXA and verified by reviewing the 

1984 Technical Analysis Report. 

Table 1 of Operating Permit No. 200TVP01, Revision 1 is provided for information and 

identification purposes only. Specifically, the emission unit rating/size provided in the table 

does not create an enforceable limit. 

EMISSIONS 

Section 2 of Operating Permit No. 200TVP01, Revision 1 lists the regulated air pollutants as 

provided in the Title V application. Table A shows the potential-to-emit (PTE)12 in TPY as 

 

12 Potential to Emit or PTE means the maximum quantity of a release of an air pollutant, considering a stationary 

source's physical or operational design, based on continual operation of all emission units within the stationary 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

 

Page 3 of 43 

provided in the Title V permit application and subsequent submittals and as revised in 

Construction Permit No. 0073-AC023 and 200CP02. As shown in the PSD Applicability table in 

the Legal and Factual Basis for the construction permit, PSD applicability was determined by 

calculating the increase in actual emissions, by pollutant, due to the change or series of changes 

since the prior PSD review in 1985. Since construction permit 0073-AC023 was PSD for CO, 

and BACT was applied, the PSD bank balance for all the pollutants went back to zero when the 

construction permit 0073-AC023 was issued. 

Table A - Milne Point Unit Potential-to-Emit (TPY)

NOX CO PM-10 SO2 VOC Total 

707 386 35 68 187 1383 

Table notes: See Emissions Summary Table included in Attachment AA 

Sources: *Revised Milne Point Improvements – Phase II Request for Amendment to Air Quality Control Permit to 

Operate NO. 9673-AA005, November 1996. 

*Response to ADEC Completeness Determination for Construction Permit No. 0073-AC023, March 10, 

2000. 

*Letter from Ross Klie (BPXA) to Jim Baumgartner (ADEC), Subject: Milne Point Unit Updated PSD 

Application Analysis (for Construction Permit 0073-AC023), June 12, 2000. 

The assessable PTE listed under condition 1.1 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 assessable emissions for the Milne Point Production Facility are 1383 TPY. 

As shown in the Emissions Summary Table included in Attachment AA, emission factors are 

based on AP-42, the manufacturer, or emission limits. This table is based on information from 

BPXA's 1996 construction permit application and subsequent submittals. 

The emissions summary table included in Attachment AA does not specifically show the VOC 

emissions from non-combustion emission units. Table B shows a summary of VOC emission 

sources from non-combustion emission units at the Milne Point Unit. This table is based on 

information from BPXA. This summary does not include the water filtration scour gas unit 

(removed) or Tanks T-2601 and T-2606 (located at C-Pad). 

Table B - Milne Point Unit VOC Emission Sources 

Emission VOC Emissions (TPY) 

Unit ID or 

Tag # 

Location Make/ Model or Other 

Identifier UnControlled 

Control 

Strategy 

Controlled

(No ID) B-Pad Process Vent 23 None 0 

(No ID) E-Pad Process Vent 23 None 0 

 CFP Produced Water Surge Tank 141.1 Collect and Flare1 0 

PU-5401A, PU5401B CFP Flotation cells 17.7 Vent Scrubber2 17.7 

V-5501, 

V-5502, 

V-5503, 

V-5511, 

V-5521 

CFP Compressor Vents 17.7 Vent Scrubber2

 17.7 

PU-5301/V4 CFP TEG Reboiler 52.6 Vent Scrubber2 52.6 

CL-5401 CFP Backwash Clarifier Purge Gas 8.8 None 8.8 

 source for 24 hours a day, 365 days a year, reduced by the effect of pollution control equipment and approved 

state or federal limitations on the capacity of the stationary source's emission units or the stationary source to emit 

an air pollutant, including limitations such as restrictions on hours or rates of operation and type or amount of 

material combusted, stored, or processed . . . as defined in AS 46.14.990(21), effective 1/18/97. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

 

Page 4 of 43 

Emission VOC Emissions (TPY) 

Unit ID or 

Tag # 

Location Make/ Model or Other 

Identifier UnControlled 

Control 

Strategy 

Controlled

 CFP Drain Purge 6.9 Vent Scrubber2 6.9 

T-2001 CFP Diesel Storage Tank 0.1 None 0.1 

T-2002 CFP Methanol Storage Tank 0 None 0 

T-5853 CFP Methanol Storage Tank 0 None 0 

T-6001 CFP Crude Oil Tank (Oil Reserve Tank) 14.9 Gas Blanket1 0 

T-6101A CFP Diesel Storage Tank 3.2 None 3.2 

T-6101B CFP Crude Oil Tank (Oil Reserve Tank) 7.5 Gas Blanket1 0 

T-6102A CFP Gasoline Storage Tank 0.1 None 0.1 

T-6102B CFP Gasoline Storage Tank 0.1 None 0.1 

 CFP Purge Gas 6.9 None 6.9 

Subtotal 323.6 114.1 

V-5417 CFP Sand Slurry Tank (Nitrogen Purge) 1.1 None 1.1 

Totals 324.7 115.2 

Table notes: 

1)BACT Limit 

2)Voluntary control 

Sources: *PSD Permit Application, Conoco, Inc. – Milne Point Project, March 16, 1984 

*Letter from H.D. Haley (Conoco) to Mr. Doug Lowery (ADEC), containing additional information on 

VOC emissions at the Milne Point Unit, October 9, 1984 

*Revised Milne Point Improvements – Phase II Request for Amendment to Air Quality Control Permit to 

Operate NO. 9673-AA005, November 1996 (Table 1-4, Sand Slurry Calculations and Tank VOC 

Emissions Report in Appendix C, and Table 3-1) 

BASIS FOR REQUIRING AN OPERATING PERMIT 

Section 2 includes a description of the regulatory classifications of the Milne Point Production 

Facility. This stationary source requires an operating permit under 18 AAC 50.325(b)(1), (b)(3), 

and (c). 

As provided in the Title V application, the Milne Point Production Facility contains emission 

units subject to federal emission standards, is classified under 18 AAC 50.300(b)(2) and (c)(1), 

and also contains emission units subject to an existing construction permit. Therefore, under 

18 AAC 50.335(e), the Title V application for the Milne Point Production Facility is required to 

include identification of the following “regulated emission units”: 

• Each emission unit subject to a standard adopted by reference in 18 AAC 50.040 under 

18 AAC 50.335(e)(2) 

• Each emission unit regulated by a standard in 18 AAC 50.055, Industrial Processes and Fuel 

Burning Equipment, under18 AAC 50.335(e)(4)(C) 

• Emission units subject to requirements in an existing Air Quality Control Construction 

Permit 18 AAC 50.335(e)(5) 

The emission sources at Milne Point Production Facility, classified as “regulated sources” 

according to the above Department regulations, are listed in Table 1 of Operating Permit No. 

200TVP01. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

 

Page 5 of 43 

CURRENT AIR QUALITY PERMITS 

Background 

On January 18, 1997, the Department implemented a divided construction and operating permit 

program. Air Quality permits issued prior to this date were called "permits-to-operate," and 

included all construction permit requirements as well as operating permit requirements. Since 

January 18, 1997, the Department has authorized construction activities through its construction 

permit program. Construction permits are usually issued separately from the Title V Operating 

Permit, but may be combined with Title V Operating Permit if requested by the Permittee. If it is 

not issued concurrently with the Title V Operating permit, then the Title V Operating Permit 

must eventually be amended to incorporate the construction permit requirements. 

Previous Air Quality Permit-to-Operate 

The most recent operating permit issued for this stationary source is permit-to-operate number 

9673-AA005 dated January 17, 1997. This permit-to-operate includes all stationary sourcespecific construction authorizations through January 17, 1997, since it was issued prior to 

January 18, 1997. These stationary source-specific requirements were included in Construction 

Permit No. 0073-AC023. 

Construction Permits 

Construction Permit No. 0073-AC023 was issued to this stationary source on July 13, 2001. The 

stationary source-specific requirements established in this construction permit are included in 

Operating Permit 200TVP01 as described below. 

Construction Permit 200CP02 is pending. Revision 1 of the operating permit, which 

incorporates all the changes authorized by 200CP02, will be public noticed concurrently with the 

preliminary decision for construction permit 200CP02. 

Title V Operating Permit Application History 

BP Exploration (Alaska) Inc. submitted a Title V application on December 1, 1997, and 

submitted additional information on March 10, 1998, and May 2, 2000. 

The information in the application has been updated based on Construction Permit No. 0073-

AC023. 

Revision 1 (pending): The department proposing to revise 200TVP01, Initial Permit, to 

incorporate changes proposed in Construction Permit No. 200CP02. The changes revise 

conditions originally imposed in Permit No. 0073-AC023 as described in Table C below. 

COMPLIANCE HISTORY 

The stationary source has operated at its current location since 1985. The stationary source was 

last inspected on December 9, 1998 and the stationary source was found to be in compliance 

with the Title V application. The inspection report indicates that Emission Unit ID(s) 9 and 10 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

 

Page 6 of 43 

had exceeded their NOX limit during a source test conducted for the purpose of determining 

compliance with the Title V permit application, and that BPXA had entered into a Compliance 

Order by Consent for the heaters. Construction Permit No. 0073-AC023 contains a condition 

prohibiting the use of liquid fuel in these heaters, which effectively resolves this problem. This 

condition has been carried over into Operating Permit No. 200TVP01. 

Review of the permit file for Permit-to-Operate 9673-AA005 indicates that this stationary source 

has no other unresolved compliance issues as of the issue date of this permit. 

STATIONARY SOURCE-SPECIFIC REQUIREMENTS CARRIED FORWARD 

State of Alaska regulations in 18 AAC 50.350(d)(1)(D) require that an operating permit include 

each stationary source-specific requirement established in a prior construction permit or permitto-operate. Table C below lists the permit condition that established a requirement in 

Construction Permit No. 0073-AC023 and the new condition in Operating Permit No. 200TVP01 

that carries the old requirement into the new permit. Table C also shows how the conditions 

originally established in Permit No,. 0073-AC023 were revised in Construction Permit 200CP02. 

In 2003 the Alaska Legislature passed HB 160, this law made several changes in verbage to 

match federal law. A ‘source’ was changed to ‘emission unit.’ A ‘facility’ was changed to 

‘stationary source.’ These changes have been made in the operating permit.
Milne Point Production Facility 

Table C - Comparison of Conditions13

Permit No. 0073-AC023 Condition Number 

Description Permit No. 

200TVP01 Condition Number 

Revisions (not including format changes) 

Permit 200TVPby 200CP02) 

Table 1 Emission Unit Inventory Table 1 Added Emission Unit ID Numbers Add Emission Units 

authorized by 200C

5 Visible emissions (VE)standard 3 Added emission units that were not part of 

construction permit action (ID(s) 11 through 13, and 17 

Added Emission Un

6 PM standard 4 Added emission units that were not part of 

construction permit action (ID(s) 11 through 13 and 17) 

Added Emission Un

7 Sulfur emission standard and 

monitoring 

5 Added emission units that were not part of 

construction permit action (ID(s) 11 through 13 and 17); added more specific MR&R rather than referring to other conditions 

Added Emission Un

8 NSPS Subpart A 60.7(b) for 

Emission unit ID(s) 1 through 4

6 No change, except cites federal regulation 

rather than paraphrases it 

No change 

9 NSPS Subpart A 60.12 for 

Emission Unit ID(s) 1 through 4

11 No change, except cites federal regulation 

rather than paraphrases it 

Added Emission Un

10.1 - NSPS Subpart A 60.7(c) for Emission Unit ID(s) 1 and 2

Added Emission Un

10.2 - NSPS Subpart A 60.7(d) for Emission Unit ID(s) 1 and 2

7 No change, except cites federal regulation 

rather than paraphrases it 

10.3 - NSPS Subpart A 60.8 for Emission Unit ID(s) 1 and 2 

8 Initial test required by 60.8 has been 

completed. Condition now requires testing as requested by the NSPS Administrator. 

No change 

10.5 - NSPS Subpart A 60.13(f) for Emission Unit ID(s) 1 and 2

12.2 No change, except cites federal regulation 

rather than paraphrases it. 

No change 

10 

10.6 - NSPS Subpart A 60.13(h) for Emission Unit ID(s) 1 and 2

12.3 No change, except cites federal regulation 

rather than paraphrases it. 

No change 

11 11.1 - NSPS Subpart GG NOX

standard and monitoring for Emission Unit ID(s) 1 and 2 

14 No longer required to maintain copies of 

documentation showing accuracy of flow meters and set NSPS NOx limit to be based 

No change 

13 This table does not include all standard and general conditions 
Milne Point Production Facility 

Permit No. 0073-AC023 Condition Number 

Description Permit No. 

200TVP01 Condition Number 

Revisions (not including format changes) 

Permit 200TVPby 200CP02) 

only on the turbine heat rate without considering controls and the primary fuel (fuel gas). Cites federal regulation rather than paraphrases it. 

11.2 - NSPS sulfur standard and monitoring for Emission Unit ID(s) 1 and 2 

17 Removed sulfur emission standard because 

all of the monitoring is for the fuel sulfur standard, cites federal regulation rather than paraphrases it. 

Added Emission Un

11.1a For turbines, requires flow 

meters for both liquid and gaseous fuel. 

14.1 No change No change 

11.2a For turbines, fuel oil sulfur 

testing - Analyze each fuel shipment rather than monthly. Allows alternative monitoring plan. 

17.1b Fuel nitrogen testing removed from the 

condition. EPA granted waiver from fuel nitrogen testing at Milne Point in a letter dated August 28, 2002. 

No change 

11.2b For turbines, fuel gas H2S 

testing – Allows length-of-stain if the sulfur content is less than 50 ppm, or a revised alternative monitoring plan for if the H2S is 

greater than 50 ppm. 

17.1a No change, except cites federal regulation 

rather than paraphrases it 

No change 

12 NSPS Subpart Dc req'ts for 

Emission Unit ID(s) 3 and 4 

13 No change, except cites federal regulation 

rather than paraphrases it 

No change 

13, 14 NSPS Subpart Kb for Emission 

Unit ID(s) 19 and 20 

0 No change, except cites federal regulation 

rather than paraphrases it 

No change 

15 Flaring req'ts 37 No change No change 16, 17 Notification req'ts 50 & 51 No change No change 18 Fuel oil req'ts 25 & 26 Minor changes per BPXA comment No change 18.2 Limits liquid fuel usage at the 

facility stationary source to 1,000,000 gallons per year 

26 No change Change six months 

19 Fuel gas req'ts 27 Clarified that the fuel gas H2S limit is an 

annual average because the limit was requested for PSD avoidance. 

No change 
Milne Point Production Facility 

Permit No. 0073-AC023 Condition Number 

Description Permit No. 

200TVP01 Condition Number 

Revisions (not including format changes) 

Permit 200TVPby 200CP02) 

20 Annual operating hours 

restrictions 

28 Log record is no longer required to be kept 

daily because emergency equipment does not operate daily. 

Change Table 2 namoperating restriction

21 Daily operating restrictions 29 Clarified that operating limit excludes 

operating time when source tests are conducted. 

Permit clarification for Emission Units Scenarios 2 and 3 

22 CO BACT for heaters when 

firing fuel gas 

30 No change No change 

23 NOX BACT for turbines 31 No change No change 

NOX BACT for heaters 30 NOX BACT limit for heaters - no change No change 

23.1a & b Permit specifies maximum load 

while operating on fuel gas and liquid fuel, with and without Direct Water Injection 

1.1 & 32.2 Changed kW limits during ramp-up periods. No change 

23.2a, 23.3b, 23.3c Initial source tests and 

installation of Low-NOx burners 

None Removed. The initial tests and installation 

of the Low-NOx burners have been completed. Provisions for completion of source tests as requested by the Department are included in the non-facility stationary source-specific condition 65. 

No change 

24 VOC BACT limits for vents 34 No change Reinstate original W

BPXA request. 

25 NOX PSD Avoidance for 

turbines 

1.1 No change No change 

26 SO2 PSD Avoidance for all 

emission Units 

1.1 SO2 PSD Avoidance for turbines (PSD 

avoidance for other emission Unit contained in conditions 26 and 27) 

No change 

27 PM PSD Avoidance for turbines 33.7 No change No change 28 CO hourly BACT for turbines 1.1 No change No change 29 CO annual BACT for turbines 1.1 No change No change 30 CO BACT for Emission Unit 

ID(s) 7 and 8 

30 No change No change 

-- PM BACT for Flare 3.b Opacity 20% limit is a surrogate for PM. 

Limit is from Permit-to-Operate 8673-

No change 
Milne Point Production Facility 

Permit No. 0073-AC023 Condition Number 

Description Permit No. 

200TVP01 Condition Number 

Revisions (not including format changes) 

Permit 200TVPby 200CP02) 

AA014 

31 Install, maintain and operate 

equipment in accordance with manufacturers parameters 

9 and 59 No change, except that the NSPS emission 

units split off from the other emission units 

No change 

38 Best Fit Correlation Method for 

developing relationships between emission rates from source tests and turbine process parameters for NOX and CO. 

21 Changes correlation submittal requirement 

from 45 days to 60 days. 

Revised to include E

Emission Unit 1 and operation on fuel ga

39 Relative Accuracy Tests for 

NOX and CO. 

22 Revised to include E

Emission Unit 1 and operation on fuel ga

40 CEMS requirements 20 No change. 51, 14 Recordkeeping – Permittee now 

required to keep most records for at least five years, and Subpart Kb tank records for life of emission unit 

80 and 0 No change, except 0 now cites federal 

regulation rather than paraphrases it 

63 - 67 VE monitoring - requires 

method 9 observation for liquid fuel-fired emission units once every 1,000 hours and once a year for gas-fired emission units

38 Changed to current VE monitoring schedule 

of 1st observation after 400 hours and 2nd

after 800 hours per year with provisions for increased frequency for liquid fuel-fired emission units. VE monitoring not required for gas-fired emission units. 

Revised to include Ereplace Emission Unsame requirements. 

68 PM monitoring – excludes 

heaters, flares, and emission units using only gaseous fuels from automatic PM test based on opacity. Requires emission units to calculate average opacity during PM source test 

41 PM monitoring is not required for any 

emission units when fired using fuel gas. 

No change 

70 VE recordkeeping –keep 

records of operating hours 

39 No change No change 
Milne Point Production Facility 

Permit No. 0073-AC023 Condition Number 

Description Permit No. 

200TVP01 Condition Number 

Revisions (not including format changes) 

Permit 200TVPby 200CP02) 

71.1, 72 VE reporting 40 No change No change 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: Draft January 15, 2004 

Page 12 of 43 

Permit No. 

0073-AC023 

Condition 

Number 

Description Permit No. 

200TVP01 

Condition 

Number 

Revisions 

(not including format changes)

5 Visible emissions (VE)standard 3 Added emission units that were not part 

of construction permit action (ID(s) 11 

through 13, and 17 

6 PM standard 4 Added emission units that were not part 

of construction permit action (ID(s) 11 

through 13 and 17) 

7 Sulfur emission standard and monitoring 5 Added emission units that were not part 

of construction permit action (ID(s) 11 

through 13 and 17); added more 

specific MR&R rather than referring to 

other conditions 

8 NSPS Subpart A 60.7(b) for Emission 

Units ID(s) 1 through 4 

6 No change, except cites federal 

regulation rather than paraphrases it 

9 NSPS Subpart A 60.12 for Emission 

Units ID(s) 1 through 4 

11 No change, except cites federal 

regulation rather than paraphrases it 

10.1 - NSPS Subpart A 60.7(c) for 

Emission Units ID(s) 1 and 2 

10.2 - NSPS Subpart A 60.7(d) for 

Source ID(s) 1 and 2 

7 No change, except cites federal 

regulation rather than paraphrases it 

10.3 - NSPS Subpart A 60.8 for Emission 

Units ID(s) 1 and 2 

8 Initial test required by 60.8 has been 

completed. Condition now requires 

testing as requested by the NSPS 

Administrator. 

10.5 - NSPS Subpart A 60.13(f) for 

Emission Units ID(s) 1 and 2 

12.2 No change, except cites federal 

regulation rather than paraphrases it. 

10 

10.6 - NSPS Subpart A 60.13(h) for 

Emission Units ID(s) 1 and 2 

12.3 No change, except cites federal 

regulation rather than paraphrases it. 

11.1 - NSPS Subpart GG NOX standard 

and monitoring for Emission Units ID(s) 

1 and 2 

14 No longer required to maintain copies 

of documentation showing accuracy of 

flow meters and set NSPS NOx limit to 

be based only on the turbine heat rate 

without considering controls and the 

primary fuel (fuel gas). Cites federal 

regulation rather than paraphrases it. 

11 

11.2 - NSPS sulfur standard and 

monitoring for Emission Units ID(s) 1 

and 2 

17 Removed sulfur emission standard 

because all of the monitoring is for the 

fuel sulfur standard, cites federal 

regulation rather than paraphrases it. 

11.1a For turbines, requires flow meters for 

both liquid and gaseous fuel. 

14.1 No change 

11.2a For turbines, fuel oil sulfur testing - 

Analyze each fuel shipment rather than 

monthly. Allows alternative monitoring 

plan. 

17.1b Fuel nitrogen testing removed from the 

condition. EPA granted waiver from 

fuel nitrogen testing at Milne Point in a 

letter dated August 28, 2002. 

11.2b For turbines, fuel gas H2S testing – 

Allows length-of-stain if the sulfur 

content is less than 50 ppm, or a revised 

alternative monitoring plan for if the H2S 

is greater than 50 ppm. 

17.1a No change, except cites federal 

regulation rather than paraphrases it 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 13 of 43 

Permit No. 

0073-AC023 

Condition 

Number 

Description Permit No. 

200TVP01 

Condition 

Number 

Revisions 

(not including format changes)

12 NSPS Subpart Dc req'ts for Emission 

Units ID(s) 3 and 4 

13 No change, except cites federal 

regulation rather than paraphrases it 

13, 14 NSPS Subpart Kb for Emission Units 

ID(s) 19 and 20 

0 No change, except cites federal 

regulation rather than paraphrases it 

15 Flaring req'ts 37 No change 

16, 17 Notification req'ts 50 & 51 No change 

18 Fuel oil req'ts 25 & 26 Minor changes per BPXA comment 

18.2 Limits liquid fuel usage at the facility to 

1,000,000 gallons per year 

26 No change 

19 Fuel gas req'ts 27 Clarified that the fuel gas H2S limit is 

an annual average because the limit 

was requested for PSD avoidance. 

20 Annual operating hours restrictions 28 Log record is no longer required to be 

kept daily because emergency 

equipment does not operate daily. 

21 Daily operating restrictions 29 Clarified that operating limit excludes 

operating time when source tests are 

conducted. 

22 CO BACT for heaters when firing fuel 

gas 

30 No change 

23 NOX BACT for turbines 31 No change 

NOX BACT for heaters 30 NOX BACT limit for heaters - no 

change 

23.1a & b Permit specifies maximum load while 

operating on fuel gas and liquid fuel, with 

and without Direct Water Injection 

1.1 & 32.2 Changed kW limits during ramp-up 

periods. 

23.2a, 23.3b, 

23.3c 

Initial source tests and installation of 

Low-NOx burners 

None Removed. The initial tests and 

installation of the Low-NOx burners 

have been completed. Provisions for 

completion of source tests as requested 

by the Department are included in the 

non-facility-specific condition 65. 

24 VOC BACT limits for vents 34 No change 

25 NOX PSD Avoidance for turbines 1.1 No change 

26 SO2 PSD Avoidance for all sources 1.1 SO2 PSD Avoidance for turbines (PSD 

avoidance for other source contained in 

conditions 26 and 27) 

27 PM PSD Avoidance for turbines 33.7 No change 

28 CO hourly BACT for turbines 1.1 No change 

29 CO annual BACT for turbines 1.1 No change 

30 CO BACT for Source ID(s) 7 and 8 30 No change 

-- PM BACT for Flare 3.b Opacity 20% limit is a surrogate for 

PM. Limit is from Permit-to-Operate 

8673-AA014 

31 Install, maintain and operate equipment in 

accordance with manufacturers 

parameters 

9 and 59 No change, except that the NSPS 

sources split off from the other sources

51, 14 Recordkeeping – Permittee now required 

to keep most records for at least five 

years, and Subpart Kb tank records for 

life of source 

80 and 0 No change, except 0 now cites federal 

regulation rather than paraphrases it 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 14 of 43 

Permit No. 

0073-AC023 

Condition 

Number 

Description Permit No. 

200TVP01 

Condition 

Number 

Revisions 

(not including format changes)

63 - 67 VE monitoring - requires method 9 

observation for liquid fuel-fired sources 

once every 1,000 hours and once a year 

for gas-fired sources 

38 Changed to current VE monitoring 

schedule of 1st observation after 400 

hours and 2nd after 800 hours per year 

with provisions for increased frequency 

for liquid fuel-fired sources. VE 

monitoring not required for gas-fired 

sources. 

68 PM monitoring – excludes heaters, flares, 

and sources using only gaseous fuels 

from automatic PM test based on opacity. 

Requires sources to calculate average 

opacity during PM source test 

41 PM monitoring is not required for any 

sources when fired using fuel gas. 

70 VE recordkeeping –keep records of 

operating hours 

39 No change 

71.1, 72 VE reporting 40 No change 

LEGAL BASIS FOR THE PERMIT CONDITIONS 

The state and federal regulations for each condition are cited in Operating Permit No. 

200TVP01. 

STATEMENT OF BASIS FOR THE PERMIT CONDITIONS 

The state and federal regulations for each condition are cited in Operating Permit No. 

200TVP01. 

Conditions 1 and 2, Emission Fees 

Applicability: 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 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. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 15 of 43 

The default assessable emissions are emissions of each air pollutant authorized by the permit 

(AS 46.14.250(h)(1)(A)). Air pollutant means any regulated air pollutant and any hazardous 

air pollutant. Therefore, assessable emissions under AS 46.14.250(h)(1)(A) means the 

potential to emit any air pollutant identified in the permit, including those not specifically 

limited by the permit. For example, hydrogen chloride (HCl) emissions from an incinerator 

are assessable emissions because they are a hazardous air pollutant, even if there is currently 

no emission limit on HCl for that class of incinerator. 

The conditions also describe how the Permittee may 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 must also be paid on any pollutant emitted whether or not the permit contains any 

limitation of that pollutant. 

This standard condition specifies that, unless otherwise approved by the Department, 

calculations of assessable emissions based on actual emissions use the most recent previous 

calendar year's emissions. Since each current year's assessable emissions are based on the 

previous year, the Department will not give refunds or make additional billings at the end of 

the current year if the estimated emissions and current year actual emissions do not match. 

The Permittee will normally pay for actual emissions - just with a one-year time lag. 

Projected actual emissions may differ from the previous year's actual emissions if there is a 

change at the stationary source, such as changes in equipment or an emission rate from 

existing equipment. 

If the Permittee does not choose to annually calculate assessable emissions, emissions fees 

will be based on “potential to emit” (PTE). 

The SO2 PTE set forth in the condition is based on liquid fuel with 0.3% by weight sulfur 

content, fuel gas with a sulfur content of 100 ppm H2S by volume, and emission factors as 

shown in Attachment AA. If the actual sulfur content of the fuel is greater than these 

assumptions, the assessable emissions calculations provided by the Permittee should reflect 

the actual sulfur content. 

Condition 3 and Section 6, Visible Emissions Standard 

Applicability: This regulation applies to operation of all fuel-burning equipment in 

Alaska. Emission Unit ID(s) 1 through 15, and 17, 18 and 18A are fuel-burning equipment. 

Factual Basis: Condition 3 requires the Permittee to comply with the federal and the state 

visible emission standards applicable to fuel-burning equipment. The Permittee shall not 

cause or allow the equipment to violate these standards. The standard does not apply to 

Emission Unit ID 16 (nonroad engine). This condition also contains the flare BACT opacity 

limit of 20% carried forward from permit No. 8636-AA014 for Emission Unit ID 18 and 

18A. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 16 of 43 

The Milne Point Flare is a gas-assisted flare that includes a flare scrubber14. The flare 

scrubber functions to separate any wet gas condensate or liquids from the vapor passing 

through the system. The flare is subject to the 20 percent state visible emissions standard and 

also to a 20 percent opacity BACT limit. Condition 3.b contains the NOX, CO, and VOC 

BACT limit for the flare using opacity as the surrogate. The Department determined that 

smoke is a sign of deterioration in flare operation, and the opacity is an indirect indicator of 

other pollutants. 

This condition has recently been adopted into regulation as a standard condition. MR&R 

requirements are listed in Section 6 of the permit. 

Gas Fired: 

Monitoring – The monitoring of gas fired emission units for visible emissions is waived, 

i.e. no source testing will be required. The Department has found that fuel gas fired 

equipment inherently has negligible PM emissions. However, the Department can 

request a source test for PM emissions from any smoking equipment. 

Reporting – The Permittee must annually certify that only gaseous fuels are used in the 

equipment. 

Liquid Fired: 

Monitoring – The visible emissions may be observed by Method-9 plan as detailed in 

Section 6. 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. 

Insignificant Emission Units: 

For Emission Unit ID(s) 14 and 15, as long as it does not exceed 400 hours of operation 

per calendar year no monitoring is required in accordance with recently issued 

Department Guidance AWQ 02-014. The Permittee must annually certify compliance 

with the opacity standard. 

Dual Fuel Fired Emission Units: 

For Emission Unit ID(s) 1, 2, 7, and 8, as long as they operate on gas monitoring is 

annual certification of compliance with the opacity standard. When they operate on 

backup liquid fuel for more than 400 hours in a calendar year monitoring as detailed in 

Section 6 is required in accordance with recently issued Department Guidance AWQ 02-

014. 

Flares: 

 

14 Sometimes referred to as knockout (K.O.) drum. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 17 of 43 

Monitoring for flares (Emission Unit ID 18 and 18A) requires Method-9 observations of 

scheduled flaring events lasting more than one hour. The Permittee must report the 

results of these observations to the Department. 

Condition 4 and Section 6, Particulate Matter (PM) Standard 

Applicability: The PM standard applies to operation of all fuel burning equipment in 

Alaska. Emission Unit ID(s) 1 through 15, and 17,18 and 18A are fuel-burning equipment. 

The SIP standard for PM applies to all fuel-burning equipment because it is contained in the 

federally approved SIP dated October 1983. 

Factual Basis: Condition 4 requires the Permittee to comply with the state PM (also 

called grain loading) standard applicable to fuel-burning equipment. The Permittee shall not 

cause or allow fuel-burning equipment to violate this standard. 

MR&R requirements are listed in Section 6 of the permit. 

Gas Fired: 

Monitoring – The monitoring of gas fired emission units for particulate matter is waived, 

i.e. no source testing will be required. The Department has found that fuel gas fired 

equipment inherently has negligible PM emissions. However, the Department can 

request a source test for PM emissions from any smoking equipment. 

Reporting – The Permittee must annually certify that only gaseous fuels are used in the 

equipment. 

Liquid Fired: 

Monitoring – The Permittee is required to conduct PM source testing if threshold values 

for opacity are exceeded. 

Recordkeeping - The Permittee is required to record the results of PM source tests. 

Reporting - The Permittee is required to report: 1) incidents when emissions in excess of 

the opacity threshold values have been observed, and 2) results of PM source tests. The 

Permittee is required to include copies of the results of all visible emission observations 

with the stationary source operating report. 

Insignificant Emission Units: 

For Emission Unit ID(s) 14 and 15, as long as it does not exceed 400 hours of operation 

per calendar year no monitoring is required in accordance with recently issued 

Department Guidance AWQ 02-014. The Permittee must annually certify compliance 

with the particulate matter standard. 

Dual Fuel Fired Emission Units: 

For Emission Unit ID(s) 1, 2, 7, and 8, as long as they operate on gas monitoring is 

annual certification of compliance with the particulate matter standard. When they 

operate on backup liquid fuel for more than 400 hours in a calendar year monitoring as 

detailed in Section 6 is required in accordance with recently issued Department Guidance 

AWQ 02-014. 

Flares: 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 18 of 43 

Monitoring of gas fired flares for particulate matter is waived, i.e. no source testing will 

be required, because of the difficulty and questionable results these tests produce when 

applied to flares. The Department has recognized this fact by incorporating the waiver in 

the State Implementation Plan adopted in November 1984 which has not been federally 

approved. No recordkeeping or reporting is required. 

Condition 5, Sulfur Compound Emissions 

Applicability: The sulfur emission standard applies to operation of all fuel-burning 

equipment in the State of Alaska. Emission Unit ID(s) 1 through 15, and 17, 18 and 18A are 

fuel-burning equipment. The SIP standard for sulfur dioxide applies because it is contained 

in the federally approved SIP dated October 1983. 

Factual Basis: The condition requires the Permittee to comply with the sulfur 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 liquid, hydrocarbon fuel (e.g. diesel or No. 2 fuel 

oil). Fuel containing no more than 0.75% sulfur by weight will always comply with the 

emission standard. For fuels with a sulfur content higher than 0.75%, the condition requires 

the Permittee to use Section 15 to calculate the sulfur-dioxide concentration using the 

equations to show that the standard is not exceeded.

Fuel sulfur testing will verify compliance. 

Fuel gas sulfur is measured as hydrogen sulfide (H2S) concentration in ppm by volume 

(ppmv). Calculations15 show that fuel gas containing no more than 4000 ppm H2S will 

always comply with this emission standard. This is true for all fuel gases, even with no 

excess air. 

Equations to calculate the exhaust gas SO2 concentrations resulting from the combustion of 

fuel gas were not included in this permit. Fuel gas with an H2S concentration of even 10 

percent of 4000 ppm is currently not available in Alaska and is not projected to be available 

during the life of this permit. 

Recordkeeping - For liquid fuel the Permittee is required to record the fuel sulfur content, 

and for fuel gas, the H2S concentration of the fuel gas. 

Reporting – The Permittee is required to report as “state” excess emissions whenever the fuel 

combusted causes sulfur compound emissions to exceed the standards in this condition. The 

Permittee is required to include the material balance calculations for fuel oil in the excess 

emissions report. 

The Permittee is required to include copies of the records mentioned in the previous 

paragraph with the stationary source operating report. 

Conditions 6 through 12, NSPS Subpart A Requirements 

Applicability: The Department has incorporated by reference the NSPS effective July 1, 

1999, for specific industrial activities, as listed in 18 AAC 50.040. 

 

15 See ADEC Air Permits Web Site at http://www.state.ak.us/dec/dawq/aqm/newpermit.htm, under "Stoichiometric 

Mass Balance Calculations of Exhaust Gas SO2 Concentration." 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 19 of 43 

Most (with the exception of some storage tanks) emission units subject to an NSPS are 

subject to Subpart A. At this stationary source, Emission Unit ID(s) 1, 1A and 2 are subject 

to NSPS Subpart GG and Emission Unit ID(s) 3 and 4 are subject to NSPS Subpart Dc and 

therefore subject to Subpart A. Emission Unit ID(s) 19 and 20 are subject to Subpart Kb 

(recordkeeping only) and, therefore, are not subject to Subpart A. 

Condition 6 - Start-up, shutdown, or malfunction record maintenance requirements in 

40 C.F.R. 60.7(b) are applicable to all NSPS emission units subject to Subpart A. 

Condition 7 - Excess emission reporting requirements in 40 C.F.R. 60.7(c) & (d) is 

applicable because there are applicable emission standards for Emission Unit ID(s) 1, 1A and 

2. The Department has included in Attachment A of the basis a copy of the federal EEMSP 

reporting form for use by the stationary source. 

Condition 8 – Performance Tests procedures in 40 C.F.R. 60.8 are applicable to Emission 

Unit ID(s) 1, 1A and 2. 

Condition 9 - Good air pollution control practices in 40 C.F.R. 60.11(d) are applicable to all 

NSPS emission units subject to Subpart A (Emission Unit ID(s) 1 through 4). 

Condition 10 – Credible Evidence procedures in 40 C.F.R. 60.11(g) are applicable to all 

NSPS emission units subject to Subpart A with applicable standards (Emission Unit ID(s) 1, 

1A and 2). 

Condition 11 - Concealment of emissions prohibitions in 40 C.F. R. 60.12 are applicable to 

Emission Unit ID(s) 1, 1A and 2. 

Condition 12 - Continuous monitoring system requirements in 40 C.F.R. 60.13(f) and (h) are 

applicable to Emission Unit ID(s) 1, 1A and 2. 

Recordkeeping requirements in 40 C.F.R. 60.7(f) are applicable to all NSPS emission units. 

(Satisfied by condition 80) 

The Flare is not subject to 40 C.F. R. 60.18 because it is a safety device and not a control 

device. It does not receive any tank vapors from any NSPS regulated emission units. 

Factual Basis: General provisions of 40 C.F.R. 60, Subpart A apply to owners or 

operators who are subject to a relevant subpart under Part 60, except when otherwise 

specified in an applicable subpart or relevant standard. The intent of Subpart A is to 

eliminate the repetition of requirements applicable to all owners or operators affected by 

NSPS. 

Condition 13, NSPS Subpart Dc Requirements 

Applicability: NSPS Subpart Dc 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). Emission Unit ID(s) 3 and 4 were installed in 1995 and 

have maximum design heat input capacities of 35 MMBtu/hr (Table 1 of Operating Permit 

No. 200TVP01); and are therefore subject to Subpart Dc. These emission units do not burn 

oil so are not subject to the SO2 or PM standards in Subpart Dc. 

Only the recordkeeping requirements in 40 C.F.R. 60.48c(g) apply to Emission Unit ID(s) 3 

and 4 because the heaters are not subject to an SO2 or PM standard. The record retention 

schedule in 40 C.F.R. 60.48c(i) is satisfied by condition 80. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 20 of 43 

Factual Basis: This condition incorporates the applicable sections of Subpart Dc, which 

deal with recordkeeping and maintenance. 

Conditions 14 through 18, NSPS Subpart GG Requirements 

Applicability: NSPS Subpart GG applies to stationary gas turbines with a heat input at 

peak load (maximum load at ISO standard day conditions16) equal to or greater than 10.7 

gigajoules per hour (10 MMBtu/hr), based on the lower heating value (LHV) of the fuels 

fired and constructed, modified, or reconstructed after October 3, 1977. Emission Unit ID(s) 

1, 1A and 2 were installed after October 3, 1977. Their heat input varies depending on 

whether Direct Water Injection (DWI) is used, however, the heat input of the turbines 

without considering any add-on equipment defines the NSPS limit for the turbines. The heat 

input for Emission Unit IDs 1, 1A and 2 is above 10.7 gigajoules/hour as shown in Table D 

below. The turbines are therefore subject to NSPS Subpart GG. 

Emission Unit IDs 1, 1A and 2 are subject to 40 C.F.R. 60.332(a)(2) when firing fuel gas. 

This standard does not apply when Emission Unit IDs 1 and 2 are fired using liquid fuel, 

which is used at the stationary source only when the fuel gas supply is curtailed or as 

required when conduction source tests. Therefore, the liquid fuel qualifies as an “emergency 

fuel” and the exemption of 40 C.F.R. 60.332(k) applies. 

Emission Unit IDs 1, !A and 2 are not subject to 40 C.F.R. 60.332(a)(1) because the 

stationary source is not an electric utility. 

Construction Permit No. 0073-AC023 condition 25.1 requires the Permittee to use Direct 

Water Injection (DWI) on the turbines to avoid PSD for NOX. Therefore, the turbines are 

subject to 40 C.F.R 60.334(a), which requires the installation of a continuous monitoring 

system to monitor and record fuel consumption and ratio of water to fuel fired in the turbine. 

The Permittee is also required to conduct source tests for the purpose of determining the 

water to fuel ratio necessary to comply with the NOX standard in condition 14. Because the 

turbines use DWI, they are also allowed an exemption to the NOX standard under 

40 C.F.R. 60.332(f) when ice fog is deemed a traffic hazard by the owner or operator. 

Fuel-bound nitrogen monitoring requirements do not apply when firing pipeline quality 

natural gas. BPXA uses only pipeline quality natural gas so no monitoring for gaseous fuel 

is included in the permit. 

Factual Basis: Conditions 14 and 17 incorporate NSPS Subpart GG NOX emission and 

sulfur compound limits into the permit. The Permittee may not allow the turbines to violate 

these standards. 

General Discussion - 

Nitrogen Oxide Standard: For a turbine subject to 40 C.F.R. 60.332, the NOX standard is 

determined by the following equation: 

STDNOX = 0.015(14.4 / Y) + F

Where, 

STDNOX = allowable NOX emissions (percent by volume at 15 percent oxygen 

and on a dry basis) 

 

16 ISO standard day conditions means 288 degrees Kelvin (59 degrees F), 60 percent relative humidity, and 101.3 

kPa (14.7 psi) as defined in 40 C.F.R 60.331(g). 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 21 of 43 

Y = manufacturer’s maximum rated heat input (kJ/W-hr), or actual 

measured heat rate based on lower heating value of fuel as measured at 

actual peak load for the affected stationary source. The value of Y shall 

not exceed 14.4 kJ/W-hr 

F = NOX emissions allowance for fuel bound nitrogen, percent by volume, 

assumed to be zero. 

The following table17 shows the peak generator load at ISO standard day conditions, 

associated heat rate, and NSPS NOX emission standards calculated using the above equation, 

in parts per million by volume on a dry basis (ppmvd). (The NOX standard in ppmvd is the 

NOX standard in percent by volume multiplied by 10,000.) The assumption that the fuelbound nitrogen is zero is a conservative assumption. The Permittee may submit a permit 

amendment request to the Department if site and fuel-specific data is available and the 

Permittee wishes to revise the NSPS NOX standard. 

Table D - NSPS NOX Standard 

Operating 

Scenario 

Heat Input 

(gigajoules/hr) 

Heat Rate 

(Btu/KW-hr) 

Heat Rate 

(KJ/W-hr) 

Y 

Fuel Bound 

Nitrogen (%) 

F 

NOX Standard 

(ppmvd) 

Fuel gas, 

without DWI 

2,514 9,532 10.05 0 215 

Sulfur Dioxide Standard: The Permittee is required to comply with one of the following 

sulfur requirements for Emission Unit ID(s) 1, 1A and 2 (turbines): 

(1) do not cause or allow SO2 emission in excess of 0.015 percent by volume, at 15 percent 

O2 and on a dry basis (150 ppmvd), or 

(2) do not cause or allow the sulfur content to exceed 0.8 percent by weight. 

The Department has only included the fuel sulfur standard listed in item (2) above in the 

permit. The Department has calculated that burning liquid fuel with 0.8 percent sulfur by 

weight results in 530 ppmvd SO2 in the exhaust and burning fuel gas with 0.8 percent sulfur 

by weight results in 389 ppmvd in the exhaust. These values are both higher than 150 ppmvd 

stated in item (1) above. Therefore, for excess emissions reporting required under 

40 C.F.R. 60.7(c), it is only necessary to report as excess emissions when the liquid fuel 

sulfur content exceeds 0.8 percent by weight or the H2S content of the fuel gas exceeds 0.8 

sulfur by weight (about 4390 ppm). 

Exemptions: Emergency gas turbines,18 military gas turbines for use in other than a garrison 

stationary source, military gas turbines installed for use as military training facilities, and fire 

fighting gas turbines are exempt from NOX emission limit in condition 14. 

Monitoring - 

 

17 From the NSPS NOX Standards Table in the Legal and Factual Basis for Construction Permit No. 0073-AC023, 

page 14. 18 Emergency Gas Turbine means any stationary gas turbine that operates as a mechanical or electrical power 

emission unit only when the primary power emission unit for a stationary source has been rendered inoperable by 

an emergency situation, as defined in 40 C.F.R. 60.331(e), effective 7/1/01. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 22 of 43 

Nitrogen Dioxide: NSPS Subpart GG NOX emission standard monitoring is incorporated 

into the permit in condition 14.1. The initial source tests required to determine the water to 

fuel ratio that must be maintained to meet the NSPS NOx limit has been completed by 

BPXA. Therefore, these conditions state the ongoing requirements that pertain to monitoring 

and reporting the water-to-fuel ratio The water-to-fuel ratio will be monitored continuously 

by the flow meters. The Permittee is required to report as "federal" excess emissions any 

time the water-to-fuel ratio falls below the level needed to keep NOX emissions below 214 

ppmvd. 

Additional periodic monitoring is included in condition 18. The additional monitoring is 

necessary to ensure that turbine emission stay below the NSPS NOX emission standard. 

Sulfur Dioxide: NSPS Subpart GG fuel sulfur monitoring is incorporated into the permit in 

condition 17.1b for liquid fuel. This condition includes a provision for the Permittee to use 

an alternative plan for monitoring liquid fuel sulfur, but only with EPA approval. If an 

alternative plan is approved, the Permittee is required to submit it to the Department before 

using it to comply with this permit. 

Sulfur Dioxide: NSPS Subpart GG fuel sulfur standard recordkeeping is incorporated into 

the permit in condition 17.2. 

Reporting - 

Nitrogen Oxides: NSPS Subpart GG NOX standard reporting requirements are incorporated 

into the permit in condition 14.2. The Permittee is required to comply with NSPS excess 

emission reporting requirements as described in condition 7 of the permit. Condition 14.2 

cites 40 CFR 60.334(c)(1), which describes exactly what is defined as excess emissions for 

the purpose of reporting under condition 7. 

Sulfur Dioxide: NSPS Subpart GG SO2 standard reporting requirements are incorporated 

into the permit in condition 17.4. For the purpose of reporting under condition 7, report any 

daily period during which the sulfur content of the fuel being fired in the gas turbine exceeds 

0.8 percent as excess emissions. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 23 of 43 

Conditions 19 through 22, Turbine NOX and CO Monitoring, Best-Fit Correlation 

Method, and Relative Accuracy Test Procedures 

Applicability: Applies because the Permittee requested to use a Best-Fit Correlation 

Method to monitor Turbine NOX and CO. 

Factual Basis: 18 AAC 50.320(a)(2) requires the department to "include terms and 

conditions as necessary to ensure that the Permittee will build and operate the proposed 

stationary source or modification in accordance with 18 AAC 50.315(e), including terms and 

conditions . . .that require the Permittee to install, use, and maintain monitoring equipment". 

This condition requires the Permittee to use a PEMS (in the form of a department-approved 

correlative relationship) or a CEMS to monitor NOX and CO emissions. 

BPXA proposed using SSPOWGEN in their construction permit application (BP 1999). In 

ex parte discussions they indicated they did not want to be limited to SSPOWGEN, but 

instead wanted to use a correlative relationship based on source tests and SSPOWGEN. The 

Department will allow use of the correlative relative relationship as long as it performs as 

well as a CEMS as indicated in Condition 19. Condition 20 contains procedures for 

developing correlative relationships. 

Condition 21 contains relative accuracy procedures to ensure that the emission rates 

predicted by the department-approved correlative relationship are representative of the actual 

NOX and CO emission rates from the turbines 

EPA has prepared a draft specification for the purpose of evaluating the acceptability of a 

PEMS at the time of installation, Example Specifications and Test Procedures for Predictive 

Emission Monitoring Systems. The Relative Accuracy Test Procedures in Condition 21 are 

based on this draft procedure. 

This methodology has been accepted by the Department for turbine NOX and CO monitoring 

as long as it meets relative accuracy requirements stated in the conditions. 

Condition 23, Operation of Closed Vent System 

Applicability: Owner requested condition for limiting venting will result in reduction of 

HAPs emissions sufficient to make give stationary source HAP minor status. 

Factual Basis: Condition requires recovery of vented vapors for a minimum of 2400 

hours per year. Monitoring requires tracking hours that the vent system is closed and 

reporting cumulative total hours to department in operating reports. 

Condition 25, Fuel Oil Sulfur Requirements 

Applicability: Owner Requested Limits for Ambient Air Quality Protection and PSD 

Avoidance for SO2, carried over from Construction Permit No. 0073-AC023 condition 18.1. 

Factual Basis: Condition 25 limits liquid fuel sulfur to 0.3 percent by weight. 

Monitoring - To ensure compliance with the fuel oil sulfur limit, monitoring of liquid fuel 

sulfur is required under NSPS for the turbines as described in condition 17.1b. Monitoring 

for all other equipment is described in condition 25.1. 

Recordkeeping and Reporting - Condition 17 only addresses the turbines, and also the owner 

requested limit of 0.30 percent fuel sulfur by weight is lower then the NSPS fuel sulfur limit 

of 0.8 percent. For this reason, additional recordkeeping and reporting for all equipment is 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 24 of 43 

required to ensure compliance with the 0.30 percent fuel sulfur limit. The Permittee is 

required to keep records of all sulfur analyses. The Permittee is required to report any time 

the fuel sulfur content is over 0.30 percent as "state" excess emissions under condition 81. 

Condition 26, Liquid Fuel Consumption Limit 

Applicability: Owner Requested Limits for Ambient Air Quality Protection and PSD 

Avoidance for SO2, carried over from Construction Permit No. 0073-AC023 condition 18.2. 

Factual Basis: Condition 26 restricts liquid fuel usage to 1,000,000 gallons for the 

equipment listed in Table 1 (stationary equipment at CFP, B pad and E pad) and all other fuel 

burning equipment that may be present on the specified pads, except for fuel burned in motor 

vehicles and in insignificant emission units, as described in the Legal and Factual Basis for 

Construction Permit No. 0073-AC023 under condition 18. This condition requires the 

Permittee to monitor fuel usage and report it to the Department, ensuring compliance with 

the fuel limit. 

Drill rigs are to be included in the 1,000,000 gallon per year liquid fuel limit. Since BPXA 

must report the fuel usage in drill rigs, this limit provides the Department with a mechanism 

to track actual emissions from drill rigs. 

The inclusion of drill rigs in the liquid fuel limit works in conjunction with a Memorandum 

of Understanding (MOU) signed by BPXA and the Department in July, 2001, which 

addresses the ambient air quality effect of drill rigs at MPU. The MOU formalized a 1998 

agreement between the Department and BPXA in which the Department agreed to exclude 

drill rigs from the ambient impact analysis for the MPU Phase II project addressed in 

Construction Permit No. 0073-AC023 only, in exchange for "real" emission reductions at the 

MPU. (In the ambient air quality analysis for this construction permit, the Department had 

determined that the Permittee was at 100 percent of the 24-hr PM-10 and 24-hr SO2 Class II 

increments (without drill rig/well servicing impacts)). The MOU requires that rotary drill 

rigs at Pad F use highline power (with certain limitations), and for all rotary drill rigs at MPU 

to use liquid fuel with a maximum sulfur content of 0.15 percent by weight when available, 

but not to exceed 0.30 percent sulfur by weight. 

Condition 27, Fuel gas Sulfur Requirements 

Applicability: Owner Requested Limits for Ambient Air Quality Protection and PSD 

Avoidance for SO2, carried over from Construction Permit No. 0073-AC023 condition 19. 

Factual Basis: This condition limits the H2S content of fuel gas to 100 ppmv, rolling 12-

month average. 

Monitoring - The fuel gas monitoring conducted per condition 17.1a satisfies the fuel 

analysis requirements for all MPU emission units since the fuel gas supply is the same for all 

MPU CFP, B-Pad, and E-Pad emission units. 

Recordkeeping and Reporting - Conditions 27.1 through 27.3 contain recordkeeping and 

reporting (including "state" excess emission reporting) requirements necessary to assure the 

Department that the Permittee will comply with the owner-requested limit of 100 ppmv. 

Condition 28, Annual Operating Restrictions 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 25 of 43 

Applicability: Owner Requested Limits for Ambient Air Quality Protection and PSD 

Avoidance for SO2, carried over from Construction Permit No. 0073-AC023 condition 20. 

Factual Basis: Condition 28 contains annual operating restrictions. These are unchanged 

from Permit-to-Operate No. 9673-AA005, with the exception of Emission Unit ID(s) 11 

through 13 and ID(s) 14 and 15 now being allowed to operate 900 and 600 hrs/yr combined, 

respectively, instead of 300 hrs/yr each. 

The operating limits include emergency operation. 

Monitoring and Recordkeeping - The Permittee is required to keep a log showing the hours 

of operation on liquid fuel. 

Reporting - The Permittee is required to report as "state" excess emissions and the amount of 

time the limit in this condition is exceeded and to include copies of the log with the 

stationary source operating report. 

(Condition 26 describes another annual limit on liquid fuel usage of 1,000,000 gallons/year 

in equipment listed in Table 1.) 

Conditions 29, Daily Operating Hourly Limits 

Applicability: Owner Requested Limits for Ambient Air Quality Protection and PSD 

Avoidance for SO2, carried over from Construction Permit No. 0073-AC023 condition 20. 

Factual Basis: Condition 29 contains daily operating limits. 

Monitoring and Recordkeeping - The Permittee is required to keep a log of the operating 

scenarios. 

Reporting - The Permittee is required to report "state" excess emissions and the amount of 

time the limit in this condition is exceeded and to include copies of the log with the 

stationary source operating report. 

Condition 30, Heater CO and NOX BACT and PSD Avoidance Limits 

Applicability: These BACT and PSD avoidance limits apply because they were carried 

over from the previous construction permit.

Factual Basis: Tables E and F show the limits, the basis of limits, and origin of limits that 

are included in Operating Permit No. 200TVP01, condition 30. 

Table E - Heater CO BACT and PSD Avoidance Limits 

Emission 

Unit ID 

Limit BACT/PSD 

Avoidance 

Basis Origin 

3 and 4 0.2 lb CO/MMBtu PSD 

Avoidance 

Emission cap to avoid PSD Permit 9573-AA001 

Amendment 1 

5 and 6 0.2 lb CO/MMBtu PSD 

Avoidance 

Emission cap to avoid PSD Permit 9573-AA001 

Amendment 1 

7 and 8 when 

firing fuel gas 

0.2 lb CO/MMBtu BACT Cannot verify origin – based on use 

of fuel gas 

Permit 8536-AA008 

7 and 8 when 

firing liquid 

fuel 

5 lb CO/1000 

gallons 

BACT AP-42, Table 1.3-1, 9/98 Permit 0073-AC023 

9 and 10 0.2 lb CO/MMBtu BACT Cannot verify origin – based on use 

of fuel gas 

Permit 8536-AA008 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 26 of 43 

CO Monitoring, Recordkeeping, and Reporting - Because source tests have shown the actual 

CO emissions to be well below the emission limit, the Department requires only that the 

Permittee follow established preventative maintenance guidelines, and maintain records of 

maintenance completed. 

Table F - Heater NOX BACT and PSD Avoidance Limits 

Emission 

Unit ID 

Limit BACT/PSD 

Avoidance 

Basis Origin 

3 and 4 0.05 lb 

NOX/MMBtu 

PSD 

Avoidance 

Emission cap to avoid PSD Permit 9573-AA001 

Amendment 1 

5 and 6 0.08 lb 

NOX/MMBtu 

and 5 TPY/unit 

PSD 

Avoidance 

Emission cap to avoid PSD Permit 9573-AA001 

Amendment 1 

7 and 8 

when firing 

fuel gas 

0.08 lb 

NOX/MMBtu 

BACT Data submitted by Conoco - 

based on gas firing and use of 

low NOX burners 

Permit 8536-AA008 

7 and 8 

when firing 

liquid fuel 

11.3 lb NOX/hr BACT Method 19 (15% air on a dry 

basis, and 29 MMBtu/hr 

(HHV)) 

Permit 0073-AC023 

9 and 10 0.08 lb 

NOX/MMBtu 

BACT Data submitted by Conoco – 

based on gas firing and use of 

low NOX burners 

Permit 8536-AA008 

NOX Monitoring and Recordkeeping - The last source tests for Emission Units ID(s) 3 

through 6 were more than five years prior to the issue date of Operating Permit No 

200TVP01, so the Department is requiring verification of the NOX emission rates by testing 

one of the heaters in each set within 180 days of permit issuance. Source testing may be 

waived if the Department determines that previous source tests are representative of current 

operating conditions. The Permittee was required to conduct a source test on Emission Unit 

ID(s) 7 and 9 (after installation of Low-NOx burners) in Construction Permit No. 0073-

AC023. These source tests and installation of Low-NOx burners in Emission Unit IDs 9 and 

10 are one-time requirements that have been met, so they are not carried forward to 

Operating Permit No. 200TVP01. 

Reporting - The Permittee is required to report "state" excess emissions and the amount of 

time a limit in this condition is exceeded. 

Conditions 31 through 33, Turbine BACT and PSD Avoidance Limits 

Applicability: These BACT and PSD avoidance limits apply because they were carried 

over from the previous construction permit. 

Factual Basis: Table G shows the limits, the basis of limits, and origin of limits that are 

included in Operating Permit No. 200TVP01 conditions 31 through 33. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 27 of 43 

Table G - Turbine CO, NOX, PM, and SO2 BACT and PSD Avoidance Limits 

Emission 

Unit ID 

Limit BACT/PSD 

Avoidance 

Basis Origin 

CO 

1, 1A and 2 No greater than 

70 lb/hr for Fuel 

Gas/Liquid Fuel 

BACT SSPOWGEN, 70 lb/hr is based 

on 0 MW and includes a 20% 

safety factor 

Permit 0073-AC023 

1, 1A and 2 No more than 

94.4 TPY, each

BACT SSPOWGEN, based on 30 days 

at 5 MW (50 lb/hr) and 225 days 

at 10 MW (19 lb/hr) 

Permit 0073-AC023 

NOX

1, 1A and 2 184 ppmvd @ 

15% O2, dry, 

corrected to ISO 

conditions. 

BACT Vendor emission data – based on 

standard combustion control 

Permit 8536-AA008, 

revised in 9473-AA010 

and 9573-AA001, 

Amendment 4 

1, 1A and 2 No more than 

625.0 TPY 

PSD 

Avoidance 

 Permit 0073-AC023 

SO2

PSD 

Avoidance 

All Calculated Permit 0073-AC023 

equipment 

Use liquid fuel 

with no greater 

than 0.3 wt% S, 

and fuel gas with 

no greater than 

100 ppmv H2S 

(rolling 12-

month average)

Ambient Air 

Quality 

Protection 

Modeling Permit 0073-AC023 

PM-10 

1,1A and 2 6.93 lb/MMscf PSD 

Avoidance 

AP-42. (EPA 2000, Table 3.1-

2a)19

Permit 0073-AC023 

Nitrogen Oxides: Condition 31 contains the NOX instantaneous BACT limit, and the annual 

NOX PSD avoidance limit, carried over from Construction Permit No. 0073-AC023. 

Monitoring - The Permittee is required to conduct source tests under condition 21.2 or 

22.1ato show compliance with the NOX BACT emission concentration. 

Although the Department is requiring monitoring of the NOX emission concentration using 

source tests, the operating load limits are necessary as well for two reasons. First, these 

assumptions were included in the ambient air quality analysis for Construction Permit No. 

0073-AC023, and any violations of the operating limits might have affected other pollutants. 

Second, violations of the BACT limit would be difficult to predict and prevent above the 

operating load limits. 

The Permittee is required to use operational limits or install Direct Water Injection on the 

turbines to comply with the annual NOX PSD avoidance limit of no more than 625 TPY.20 

The Permittee is required to monitor the NOX rate in pph using an approved correlative 

relationship or a CEMS as provided in condition 19, and compile the 12-month rolling total 

to ensure that the 625 TPY limit is not exceeded. 

 

19

MMscf

lb

MMscf

scf

scf

Btu

Btu

MMBtu

MMBtu

lb 1050 1000 6.93

1000

0.0066 1

× × × =

20 BPXA notified the Department of DWI installation on September 23, 2001. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 28 of 43 

Reporting - The results of source tests are included with the stationary source operating 

report under condition 21.7. 

Carbon Monoxide: Condition 31 contains the CO BACT limits carried forward from 

Construction Permit No. 0073-AC023. 

The Permittee requested in their application of September 22, 2003 that the CO BACT limit 

be changed from 94.4 TPY for each turbine to 188.8 TPY for both turbines. The Department 

is denying this request because, with the installation of the new turbine, they are not similar 

units and does not want to bubble dissimilar units. 

Monitoring and Recordkeeping - The Permittee is required to monitor the CO emission rate 

in pph using an approved correlative relationship or a CEMS as provided in condition 19, and 

compile the 12-month rolling total to ensure that the 94.4 TPY limit is not exceeded. 

Reporting - The Permittee is required to report "state" excess emissions. 

Sulfur Dioxide: Condition 31 (PSD avoidance for the turbines) refers to the sulfur limits and 

MR&R in conditions 25 and 27 for all equipment, to keep SO2 emissions below the PSD 

threshold. This condition was a PSD avoidance requirement carried forward from 

Construction Permit No. 0073-AC023. 

Particulate Matter: Condition 31 limits PM emissions from the turbines to 28 TPY. This 

condition was a PSD avoidance requirement carried forward from Construction Permit No. 

0073-AC023. 

Monitoring - The Permittee is required to monitor fuel gas and liquid fuel usage for the 

turbines using the fuel flow meters required by condition 14.1, then calculate PM-10 

emissions as described in conditions 33.7a and 33.7b. 

Since this is a PSD-avoidance limit, the construction permit required the Permittee to conduct 

source tests for all of the possible operational scenarios (both fuel gas- and liquid fuel-firing, 

with and without DWI). Although PM from fuel gas-firing is expected to be significantly 

lower than for fuel-oil-firing, it does occur under certain conditions, for instance incomplete 

combustion of the carbon in the fuel. The liquid fuel emission factors are required to be 

determined based on the high heating value (HHV) of the liquid fuel. These requirements 

have been carried over to Operating Permit No. 200TVP01. 

Recordkeeping - The Permittee is required to calculate and record the 12-month total PM-10 

emissions for the turbines and the first time that the 12-month total from this condition 

exceeds 26 tons, the Permittee is required to conduct source tests to verify the AP-42 

emission factor. 

Reporting - The Permittee is required to report "state" excess emissions and to attach a 

summary of the 12-month PM-10 emission to the stationary source operating report. 

Condition 34, Vent BACT and PSD Avoidance Limits 

Applicability: These BACT and PSD avoidance limits apply because they were carried 

over from the previous construction permit.

Factual Basis: Table H shows the limits, the basis of limits, and origin of limits that are 

included in Operating Permit No. 200TVP01, condition 34.

Table H - Vent BACT and PSD Avoidance Limits 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 29 of 43 

Emission 

Unit ID 

Limit BACT/PSD 

Avoidance 

Basis Origin 

23 Provide a gas blanket and 

back pressure relief valve 

BACT Permit 8536-AA008 

24 Collect and Flare vent gas BACT Collect and reinject fuel gas 

downhole, or flare 

Permit 0073-AC023 

21 and 22 Use for Emergency 

purposes only Limit Well 

Pad B vents to 36.5 tpy of 

VOC emiisions 

BACT Permit 8536-AA008 

Volatile Organic Compounds: Condition 0 contains a VOC BACT limit of gas blanketing and a 

back-pressure relief valve on the oil reserve tanks (Emission Unit ID 23). Condition 0 contains 

the VOC BACT limits for the Produced Water Surge Tank. Construction Permit No. 0073-

AC023 condition 24.2 prohibits venting of gas to the atmosphere from the produced water surge 

tank and requires isolation of the pressure control valve that goes to the vent header. BPXA 

completed this requirement on May 29, 2001. There is another pressure control valve that goes 

to the flare that is not required to be isolated. A 1984 BACT limit was apparently left out of the 

Permit-to-Operate 9473-AA010 and all subsequent permits. During an audit on October 2 and 3, 

2003 this oversight was noted and BPXA then asked for the vents to be included in the existing 

construction and operating permit. In Permit 8536-AA008 the venting from Well Pad B and 

Well Pad E were assumed to be due to emergency venting. These limits were assumed to be in 

place for emission estimates for PSD avoidance for Construction Permit No. 0073-AC023. 

The majority of the process vent header VOC emissions occur from the fuel gas controlled by a 

rotometer that is used as blanket purge gas on the methanol and sump tanks. The second source 

of emissions is the sump tank working and breathing losses. The third source is the water pig 

launcher. The annual VOC emissions are estimated as 2.60 tpy for the rotometer fuel gas flow, 

16.5 lbs/yr for the sump tank, and zero for the water pig launcher. The fuel gas has a VOC 

percentage of 8.4%, by weight, based on five fuel gas samples that have an average molecular 

weight of 18.34 lb/lbmole.21 

Monitoring - These requirements require monthly totalizing by the rotometer 

Recordkeeping - The Permittee is required to keep records showing that well pad B and well 

pad E vents are used for emergency purposes only. 

Reporting - Include with the stationary source operating report the records showing that well 

pad B and well pad E vents are used for emergency purposes only. 

Conditions 35 and 36, Fuel Consumption and Hours of Operation Monitoring 

Applicability and Factual Basis: The old operating permit No. 9673-AA005 

contained conditions that must be carried forward to this Title V permit. These conditions 

contain requirements to measure fuel consumption so that emission levels may be calculated 

and operating hours monitoring for all fuel burning equipment, except flares. 

Condition 37, Flaring 

 

21 From Fax note from Julie Ackerlund, Ackerlund, Inc. to William Ashton, ADEC on December 12, 2003. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 30 of 43 

Applicability: Ambient air quality protection requirement. 

Factual Basis: This condition provides the Department with actual information on flaring, 

in order to ensure that emission estimates from flaring provided in the PSD application are 

representative of actual emissions. 

Conditions 38 through 45 (Section 6), Visible Emissions and PM Monitoring Plan 

Applicability: Applies because these conditions detail the monitoring, recordkeeping, 

and reporting required in conditions 3 and 4. 

Factual Basis: Each permit term and condition must include MR&R requirements 

showing verifiable compliance with each permit term and condition. The Permittee must 

establish by actual visual observations which can be supplemented by other means, such as a 

defined Stationary source Operation and Maintenance Program, that the stationary source is 

in continuous compliance with the State's emission standards for visible emissions and 

particulate matter. The correlation between particulate matter and visible emissions that is 

the basis for this monitoring procedure is discussed under conditions 3 and 4. 

These conditions detail a stepwise process for monitoring compliance with the State's visible 

emissions and particulate matter standards for liquid fired emission units. Equipment types 

covered by these conditions at the Milne Point Production Facility are liquid fuel-fired 

internal combustion engines and dual fuel-fired turbines and heaters. Initial monitoring 

frequency schedules are established along with subsequent reductions or increases in 

frequency depending on the results of the self-monitoring program. The monitoring 

frequency in condition 19 is not as frequent as in 18 AAC 50.346(c) because all the 

monitored equipment is emergency equipment or equipment fired using liquid fuel only in 

emergencies and are expected to seldom experience more than 400 hours of operation per 

year. 

Monitoring frequencies for liquid hydrocarbon fuels, are detailed in these conditions. 

Reasonable action thresholds are established in these conditions that require the Permittee to 

progressively address potential visible emission problems from sources either through 

maintenance programs and/or more rigorous tests that will quantify whether a specific 

emission standard has been exceeded. 

More details are found in the Factual Basis statement for Conditions 3 and 4. 

Condition 46, (Section 6), Visible Emissions MR&R Plan for Flares 

Applicability: Applies because this condition details the monitoring, recordkeeping, and 

reporting required to demonstrate compliance with condition 3 for gas-fired flares. 

Factual Basis: Condition 46 was developed to provide a standardized version of flare 

monitoring that is not dependent upon the type or design of upstream equipment. It has been 

claimed that gas-fired flares normally burn without emitting visible emissions, but actual 

field data demonstrating this assumption is not available. However, gas-fired flares have 

been shown to smoke when a control device, i.e. a knockout drum, flare scrubber, gas or 

steam assist, or vapor recovery system malfunctions. Thus, the condition sets out a protocol 

to collect actual field data to determine compliance with the 20% opacity standard for flares. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 31 of 43 

A recent Department analysis of industry flaring operations indicates that 49% of the gas 

flared (by volume) is for pilot/purge, 25% is for flaring less than one hour, and 26% is for 

flaring that lasts more than one hour. Pilot/purge flaring constitutes half of all flaring by 

volume and is continuous in nature and can be observed at any time. This type of flaring has 

not caused violations of the opacity standard in the past and can be checked at any time by 

agency inspectors. The remaining half of the flaring volume is split evenly between less than 

and greater than one-hour duration. Therefore, the monitoring scheme in this condition 

addresses the half of the non-continuous flaring operations that are scheduled and for which a 

certified observer can reasonably be located onsite. 

Since it is impractical to require facilities to have a certified Method-9 opacity reader on site 

for unpredictable emergency flaring, the monitoring protocol requires Method-9 readings 

only during scheduled flare events. Scheduled events such as those generated by 

maintenance activities and well testing of greater than one-hour in duration will be observed. 

These one-hour events are currently quantified and reported to the Alaska Oil and Gas 

Conservation Commission for other reasons and thus provides a confirming information 

record of the occurrence of these events. Only those events as defined in the condition need 

to be monitored. If no events meeting this definition occur during the life of the permit then 

no monitoring is required. 

Since only flaring that is scheduled and exceeds one hour is required to be observed, 

operators will have time to provide certified Method-9 readers onsite. Most oil and gas 

production facilities in Alaska are located at remote sites, so it is not reasonable to selfmonitor all or even a large sample of the flaring that occurs. Data collected from planned 

events will help the Department refine this monitoring scheme during future permit cycles. 

Process upsets and emergency events that may or may not exceed one hour occur randomly 

and do not lend themselves easily to periodic monitoring. At this time, the Department will 

rely on stationary source excess emission reports, citizen complaints, and agency inspections 

for information concerning these short term and emergency events. 

Conditions 47 and 48, Halon Prohibitions 

Applicability: These prohibitions apply to all facilities that use halon for fire 

extinguishing and explosion inertion. The Milne Point Production Facility uses halon and is 

therefore subject to the federal regulations contained in 40 CFR 82. 

Factual Basis: These conditions incorporate applicable 40 CFR 82 requirements. The 

Permittee may not cause or allow violations of these prohibitions. No additional MR&R 

requirements are required to ensure compliance with these federal requirements. 

Condition 49, Emission Unit Aggregation 

Applicability: The aggregated potential emissions are the potential emissions from all 

emission units installed after August 7, 1980, for the purpose of determining applicability 

with the modification requirements of 18 AAC 50.300(h)(3). 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 32 of 43 

Factual Basis: The Milne Point Unit consists of the Central Facilities Pad (CFP) and 

other well pads. At the time of the 1996 PSD application, the stationary source consisted of 

the CFP and pads A through N. The Department determined that, except for B-Pad and EPad, the other non-contiguous well pads were excluded from the "existing permit [No. 9573-

AA001] since the combined ambient impacts are insignificant". O-Pad was proposed in 

1996 (BP 1996) but was not constructed as of July 1998. In May 2000, BPXA met with the 

Department to discuss construction of S-Pad. BPXA asserted that S-Pad should be 

disaggregated from CFP for the same reasons that C-Pad is disaggregated. The Department 

did not contradict that assertion and has allowed S-Pad to be disaggregated from the Milne 

Point Unit CFP for the purpose of determining applicability with the modification 

requirements of 18 AAC 50.300(h)(3). 

Construction Permit No. 0073-AC023, includes CFP, B-Pad and E-Pad. A Memorandum of 

Understanding (MOU) dated July 17, 2001 stipulates requirements for drill rigs at the Milne 

Point Unit. The MOU formalized a 1998 agreement between the Department and BPXA in 

which the Department agreed to exclude drill rigs from the ambient impact analysis for that 

project only, in exchange for "real" emission reductions at the MPU. 

Operating Permit No. 200TVP01 includes CFP, B-Pad, and E-Pad. Pads A through N 

(except for B and E) and S-Pad are disaggregated for the reasons cited above. The 

Department will need to determine the aggregation status of any additional well pads 

(including O-Pad) or nearby facilities on a case-by-case basis. 

Conditions 50 and 51, Notification Requirements and Procedures 

Applicability: Ambient air quality protection requirements carried over from 

Construction Permit No. 0073-AC023. 

Factual Basis: These conditions require the Permittee to notify the Department prior to 

doing anything that will affect the stationary source’s impact on ambient air. These 

requirements are separate from the notification requirements for the Construction 

Permit 0073-AC023. 

Conditions 52 through 55, Insignificant Emission Units 

Applicability: These general emission standards apply to all industrial processes fuelburning equipment, and incinerators regardless of size.

Factual Basis: Conditions 52 through 55 require the Permittee to comply with the general 

standards 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 emission units at this stationary source do not 

need specific monitoring, recordkeeping and reporting to ensure compliance with these 

conditions. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 33 of 43 

Condition 56, NESHAPS Subparts A, Applicability Determinations (Recordkeeping 

Only) 

Applicability: NESHAPs Subpart A requirements apply to facilities categorized in 40 

C.F.R. 63. 

Factual Basis: The condition requires the Permittee to retain records of NESHAP 

applicability determinations. 

Condition 57, Asbestos NESHAP 

Applicability: The asbestos demolition and renovation requirements apply if the 

Permittee engages in asbestos demolition or renovation. 

Factual Basis: The condition requires the Permittee to comply with asbestos demolition 

or renovation requirements in 40 C.F.R. 61, Subpart M. 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 58, Refrigerant Recycling and Disposal 

Applicability: Applies if the Permittee engages in the recycling or disposal of certain 

refrigerants. 

Factual Basis: 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. 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 59, Good Air Pollution Control Practice 

Applicability: Applies to all emission units, except NSPS regulated emission units, i.e. 

Emission Unit ID(s) 1, 1A, 2, 3, and 4. 

Factual Basis: The condition requires the Permittee to comply with good air pollution 

control practices for all emission units. 

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. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 34 of 43 

Condition 60, Dilution 

Applicability: 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. No specific monitoring for this condition is 

practical. Other than the required annual certification, no monitoring, recordkeeping or 

reporting is necessary for this condition. The Permittee presently does not dilute emissions. 

Dilution would probably require a physical change to the stationary source. A reasonable 

inquiry and certification by a responsible official as to whether such changes occurred over 

the reporting period is sufficient to assure compliance. 

Condition 61, Reasonable Precautions to Prevent Fugitive Dust 

Applicability: Bulk material handling requirements apply to the Permittee because the 

Permittee could engage in bulk material handling, transporting, or storing; or will engage in 

industrial activity at the stationary source. 

Factual Basis: The underlying regulation, 18 AAC 50.045(d), requires the Permittee to 

take reasonable action to prevent particulate matter (PM) from being emitted into the ambient 

air. 

Condition 62, Stack Injection 

Applicability: 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: The condition 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). No specific 

monitoring for this condition is practical. Other than the required annual certification, no 

monitoring, recordkeeping or reporting is necessary for this condition. The Permittee 

presently does not inject wastes into stacks. Waste injection would probably require a 

physical change to the stationary source. A reasonable inquiry and certification by a 

responsible official as to whether such changes occurred over the reporting period is 

sufficient to assure compliance. In addition, compliance is ensured by agency inspections, 

because the emission unit or stack would need to be modified to accommodate stack 

injection.

Condition 63, Open Burning 

Applicability: 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: The condition requires the Permittee to comply with the regulatory 

requirements when conducting open burning at the stationary source. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 35 of 43 

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 64, which requires a record of complaints. Therefore, the Department does not 

believe that additional monitoring is warranted. 

Condition 64, Air Pollution Prohibited 

Applicability: Air Pollution Prohibited requirements apply to the stationary source 

because the stationary source will have emissions. 

Factual Basis: 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. 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. 

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 and summary of 

the investigation and corrective actions undertaken for these complaints and to submit copies 

of these records upon request of the Department. 

The Department will determine whether the necessary actions were taken. No corrective 

actions are necessary if the complaint is frivolous or there is not a violation of 

18 AAC 50.110, however this condition is intended to prevent the Permittee from prejudging 

that complaints are invalid. 

Condition 65, Technology-Based Emission Standard 

Applicability: 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 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. The conditions of this permit list applicable technology-based emission standards 

and require excess emission reporting for each standard in accordance with condition 81. 

Excess emission reporting under condition 81 requires information on the steps taken to 

minimize emissions, the report required under condition 81 is adequate monitoring for 

compliance with this condition. 

Condition 66, Permit Renewal 

Applicability: Applies if the Permittee intends to renew the permit. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 36 of 43 

Factual Basis: The Permittee is required to submit an application for permit renewal by 

the specific dates applicable to Milne Point Production Facility as listed in this condition. 

Monitoring, recordkeeping, and reporting for this condition consist of the application 

submittal. No additional requirements are necessary to ensure compliance with this 

condition. 

Condition 67, Requested Source Tests 

Applicability: Applies because this is a standard condition to be included in all permits. 

Factual Basis: The Permittee is required to conduct source tests as requested by the 

Department. Monitoring consists of conducting the requested source test, and no 

recordkeeping or reporting requirements are necessary to ensure compliance with this 

condition. 

Conditions 68 through 70, Operating Conditions, Reference Test Methods, Excess 

Air Requirements 

Applicability: Apply because the Permittee is required to conduct source tests by this 

permit. 

Factual Basis: The Permittee is required to conduct source test as set out in conditions 68 

through 70. These conditions supplement the specific monitoring requirements stated 

elsewhere in this permit. The test reports required by condition 75 adequately monitor 

compliance with conditions 68 through 70, therefore no additional MR&R requirements are 

necessary to ensure compliance with these conditions. 

Condition 71, Test Exemption 

Applicability: Applies when the emission unit exhaust is observed for visible emissions. 

Factual Basis: As provided in 18 AAC 50.345(a), 5/03/02, 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 72 through 75, Test Deadline Extension, Test Plans, Notifications and 

Reports 

Applicability: 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. Because these standard conditions supplement specific monitoring requirements 

stated elsewhere in this permit no MR&R is required. The source test itself is adequate to 

monitor compliance with this condition. 

Condition 76, Particulate Matter (PM) Calculations 

Applicability: Applies when the Permittee tests for compliance with the PM standard. 

Factual Basis: The condition incorporates a regulatory requirement for PM source tests. 

Because this condition supplements specific monitoring requirements stated elsewhere in this 

permit, no MR&R is required to ensure compliance with this condition. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 37 of 43 

Condition 77, Certification 

Applicability: This is a standard condition to be included in all permits. Applies because 

every permit requires the Permittee to submit reports. 

Factual Basis: This condition requires the Permittee to certify all reports 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 operating report, even 

though it must still be submitted more frequently than the stationary source operating report. 

This condition supplements the reporting requirements of this permit, therefore no additional 

MR&R is necessary to ensure compliance with this condition. 

Condition 78, Submittals 

Applicability: Applies because the Permittee is required to send reports to the 

Department. 

Factual Basis: This condition requires the Permittee to send submittals to the address 

specified in this condition. Receipt of the submittal at the correct Department office is 

sufficient monitoring for this condition. This condition supplements the reporting 

requirements of this permit, therefore no additional MR&R is necessary to ensure 

compliance with this condition. 

Condition 79, Information Requests 

Applicability: Applies to all Permittees, and incorporates a standard condition. 

Factual Basis: This condition incorporates a standard condition in regulation, which 

requires the Permittee to submit information requested by the Department. Receipt of the 

requested information is adequate monitoring. 

Condition 80, Recordkeeping Requirements 

Applicability: 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 adequate evidence of compliance with this requirement, therefore, no 

additional MR&R is required. 

Condition 81, Excess Emission and Permit Deviation Reports 

Applicability: Applies when the 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 condition mandates the use of the Department's reporting form. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 38 of 43 

The reports themselves and the other monitoring records required under this permit provide 

an adequate monitoring of whether the Permittee has complied with the condition. 

Therefore, no additional MR&R is necessary to ensure compliance with this condition. 

Please note that there may be additional federally required excess emission reporting 

requirements. 

Condition 82, NSPS and NESHAP Reports 

Applicability: Applies to facilities subject to NSPS and NESHAP federal regulations. 

Factual Basis: The condition supplements the specific reporting requirements in 

40 C.F.R. 60 and 40 C.F.R. 61. The condition does not need any MR&R. The reports 

themselves are adequate monitoring for compliance with this condition. 

Condition 83, Stationary source Operating Reports 

Applicability: Applies to all permits. 

Factual Basis: The condition restates the requirements for reports listed in regulation. 

The condition supplements the specific reporting requirements elsewhere in the permit and 

does not need any MR&R. The reports themselves are adequate monitoring for compliance 

with this condition. 

Condition 84, Annual Compliance Certification 

Applicability: Applies to all Permittees. 

Factual Basis: This condition specifies the periodic compliance certification 

requirements, and specifies a due date for the annual compliance certification. Because this 

requirement is a report, no MR&R is needed. 

Conditions 85 through 91, Standard Conditions 

Applicability: Applies because these are standard conditions to be included in all 

permits. 

Factual Basis: These are standard conditions required for all operating permits. 

Condition 92, Permit Shield 

Applicability Applies because the Permittee has requested a shield for the applicable 

requirements listed under this condition. 

Factual Basis: Table 6 of Operating Permit No. 200TVP01 shows the permit shields that 

the Department granted to the Permittee. The permit conditions set forth the requirements 

that the Department determined were not applicable to the stationary source. The following 

table shows the requests that were denied and the reason that they were denied. The 

Department based the determinations on the permit application, past operating permit, 

construction permits and inspection reports. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 39 of 43 

Table I - Permit Shields Denied 

Shield requested for: Reason for shield 

request: 

Reason for request 

denial: 

Stationary source-Wide

18 AAC 50.045(b) - 

Prohibitions 

The permit implements all 

applicable air quality 

requirements for the stationary 

source. Since compliance 

with the permit will constitute 

compliance with applicable 

local, state, or federal air 

quality laws, this requirement 

is not directly applicable to the 

stationary source. 

18 AAC 50.045(c) - 

Prohibitions 

This requirement will be 

implemented through 18 AAC 

50.201, which is otherwise 

addressed in the permit. This 

requirement is not applicable 

because the Department will 

impose any special 

requirements to protect 

ambient air quality through 

permit conditions adopted 

under 50.201. 

These prohibitions are 

ongoing requirements and 

therefore cannot be shielded. 

They have not been placed in 

the permit because they add 

no value to the permit with 

respect to controlling 

stationary source emission 

sources. These prohibitions 

remain in effect because they 

are in regulation whether they 

appear in the stationary source 

operating permit or not. 

Shielding the applicant from 

subparagraph (b) for instance 

would have the effect of 

shielding the applicant from 

all requirements contained in 

the Air Quality Control 

Regulations including the 

requirement to obtain a permit 

if the shield requested is 

granted. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 40 of 43 

Shield requested for: Reason for shield 

request: 

Reason for request 

denial: 

Liquid Fuel-Fired Emergency 

Internal Combustion Engines 

PED-0110A, PED-0110B, 

PU-4703A, and PU-4703B: 

AQC Permit No. 9673-AA005 

Condition 7, Exhibits A, B, 

C, and D 

These combustion emission 

units are insignificant per 18 

AAC 50.335(r). They have 

actual emission rates less than 

those listed in 18 AAC 335 

(r)(1) through (15). 

Emission unit-specific limits 

and monitoring, 

recordkeeping, and reporting 

requirements were included in 

AQC Construction Permit No. 

0073-AC023, which rescinded 

AQC Permit No. 9673-

AA005. 

Gas-Fired Heaters H-4510A 

and H-4510B: 

AQC Permit No. 9673-AA005 

Exhibit B Carbon Monoxide 

The CO value of 0.20 

lb/MMBtu is not an emission 

limit, it is an emission 

estimate. 

Both AQC Permit 9673-

AA005 and the 1985 PSD 

permit identify 0.20 

lb/MMBtu as the limit for CO 

emissions. 
Permit No.: 200TVP01 Statement of Basis 

Milne Point Production Facility Revision 1: May 25, 2004 

Page 41 of 43 

Attachment A 

Figure 1--Summary Report -- Excess Emission and Monitoring System Performance 

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________________________ 

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 
Milne Point Production Facility 

Attachment AA 

 BP Milne Point Permit No. 200TVP01 Emission Spreadsheet 

Emission Unit # 1,2 3,4 5,6 9.10,11 12 13,14 15,16 17,18 19 

Stationary source Tag PU-0701 H-5302A H-4510A PU-0101A,B H-5701A H-2001A PU-0110A PU-2004 

 PU-0801 H-5302B H-4510B PU-0101C H-5701B H-2001B PU-0110B 

Equipment Type Turbines Heaters Heaters Engines Flare Heatersb Heaters Emer.Engi

ne 

Engine V

Number units 2 2 2 2 3 1 2 2 2 2 1 

Permitted under PSD 

1985 

yes yes no No no yes yes no yes no yes 

Typical fuela NG AFO NG NG AFO NG NG AFO NG AFO AFO 

Continous Rated 

Capacity (CRC) 

243.11 500,000 35.0 14.4 1.5 0.340 29.0 29.0 12.0 12.0 600.0 

-CRC units MMBtu/hr Gal/yr 

(each) 

MMBtu/hr MMBtu/hr MW MMscf/day MMBtu/hr MMBtu/hr MMBtu/hr hp hp 

Additional information 25.0 25.2 n/a n/a 2,010.36 n/a n/a 0.3 n/a 0.3 0.3 

-units MW MW n/a n/a hp n/a n/a % fuel 

sulfur 

n/a % fuel 

sulfur 

% fuel sulf

fuel flow (lb/hr) n/a 13,557 n/a n/a 735.3 n/a n/a 13,557 n/a n/a n/a 

Heat rate (BTU/hp-hr) n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 

Assumed Annual Load 100% n/a 100% 100% n/a n/a 100% 100% 100% n/a n/a 

Operational time (NOX, 

VOC) 

8,760 0 8760 8760 300 365 8760 0 8760 300 300 

units hrs/yr hrs/yr hrs/yr hrs/yr Hrs/yr days/yr hrs/yr hrs/yr hrs/yr hrs/yr hrs/yr 

Operational time ( CO, 

SO2, PM) 

8,510 250 8760 8760 300 365 8660 100 8760 300 300 

units hrs/yr hrs/yr hrs/yr hrs/yr Hrs/yr days/yr hrs/yr hrs/yr hrs/yr hrs/yr hrs/yr 

heat value of fuel 1,120 n/a 1,120 1,120 19,700 1,120 1,120 0.123 1,120 0.123 0.123 

-units of heat value BTU/scf **** BTU/scf BTU/scf BTU/lb BTU/scf BTU/scf MMBTU/ga

l 

BTU/scf MMBTU/ga

l 

MMBTU/g

fuel density n/a 6.78 n/a n/a n/a 10.6 n/a n/a n/a n/a n/a 

Operational limit none 17,500 n/a n/a 89.6 n/a 100 300 300 

units hp n/a n/a MWhr-day n/a hr/yr hr/yr hr/yr 

other limits 21,371 7,771 combined on diesel on diesel on diese

units kw - no 

DWI 

kw - no DWI 

 NOx emission rate 184.00 184.00 0.048 0.08 10.60 0.068 0.08 0.08 14.0 14.0  -units ppm ppm lb/MMBtu lb/MMBtu g/hp-hr lb/MMBtu lb/MMBtu lb/103 gal lb/MMBtu g/hp-hr g/hp-hr  -safety factor n/a n/a 1.0 n/a n/a n/a n/a n/a n/a  -from Manufactur

er 

Limit Vendor+1.

2 sf 

AP-42 5/84 PSD 

appl 

AP-42 5/84 PSD 

appl 

AP-42 AP-42 

NOx TPY per unit 7.36 5.05 7.05 4.73 10.16 0.00 4.20 0.06 2.78 NOx check g/sec 0.2117 0.1451 0.2027 0.1359 0.2923 0.0000 0.1210 0.0001 0.0799 NOx TPY 14.7 10.1 21.1 4.7 20.3 0.0 8.4 0.1 2.8 NOX TPY w/emission 

caps 

625.0 14.7 10.1 21.1 4.7 20.3 8.4 0.1 2.8 

Sulfur content 100 0.30 100 100 0.30 100 100 0.30 100 0.30 0.30 
Milne Point Production Facility 

 -units % ppm ppm % ppm ppm % ppm % % 

SO2 emission rate 16.89 0.006 16.89 16.89 0.002 16.89 16.89 0.433 16.89 0.002 0.002  -units lb/MMscf lbSO2/lb 

fuel 

lb/MMscf lb/MMscf LbSO2/hphr lb/MMscf lb/MMscf lb/MMBtu lb/MMscf lbSO2/hp- hr lbSO2/hp-

 -from calculated calculated calculated calculated Calculated calculated calculated calculated calculated calculated calculateSO2 TPY per unit 15.60 10.17 2.31 0.95 0.64 1.05 1.89 0.63 0.79 0.00 0.18 SO2 check g/sec 0.4487 0.2926 0.0665 0.0274 0.0185 0.0301 0.0545 0.0181 0.0228 0.0001 0.0052 SO2 TPY 31.2 20.3 4.6 1.9 1.9 1.0 3.8 1.3 1.6 0.0 0.2 PM10 emission rate 6.930 0.012 6.2 6.2 0.30 40.0 6.2 2.0 6.2 1 1  -units lb/MMscf lb/MMBtu lb/MMscf lb/MMscf g/hp-hr ug/l lb/MMscf lb/103 gal lb/MMscf g/hp-hr g/hp-hr  -from AP-42 AP-42 AP-42 AP-42 Vendor+1.

2 sf 

AP-42 AP-42 AP-42 Manufactur

er 

AP-42 AP-42 

PM10 TPY per unit 0.85 0.35 0.17 1.64 0.70 0.03 0.29 0.00 0.20 PM10 check g/sec 0.024 0.000 0.005 0.047 0.020 0.001 0.008 0.029 0.029 PM10 TPY 1.7 0.7 0.5 1.6 1.4 0.1 0.6 0.0 0.2 PM10 TPY w/emission 

caps 

28.0 1.70 0.70 0.51 1.64 1.39 0.06 0.58 0.01 0.20 

CO max ER 70 70 0.20 0.20 6.6 0.37 0.20 5.0 0.20 3.03 3.03  -units pph pph lb/MMBTU lb/MMBtu g/hp-hr lb/MMBtu lb/MMBtu lb/103 gal lb/MMBtu g/hp-hr g/hp-hr  -from limit Limit Vendor+1.

2 sf 

AP-42 3/84 PSD 

appl 

AP-42 limit AP-42 AP-42 

CO TPY per unit 94.4 30.66 12.61 4.39 25.71 25.11 0.07 10.51 0.01 0.60 CO check g/sec 0.8820 0.3629 0.1262 0.7397 0.7224 0.0021 0.3024 0.0872 0.0872 CO TPY total 61.3 25.2 13.2 25.7 50.2 0.1 21.0 0.0 0.6 CO TPY w/ emission caps 

188.8 61.3 25.2 13.2 25.7 50.2 0.1 21.0 0.0 0.6 

VOC ER 0.087 0.062 5.8 5.8 0.2 0.140 5.8 0.2 5.8 1.12 1.12  -units g/hp-hr g/hp-hr lb/MMscf lb/MMscf g/hp-hr lb/MMBtu lb/MMscf lb/103 gal lb/MMscf g/hp-hr g/hp-hr  -from AP-42 Manufactur

er 

AP-42 AP-42 Vendor+1.

2 sf 

AP-42 AP-42 AP-42 AP-42 AP-42 AP-42 

VOC TPY per unit 28.14 0.58 0.79 0.33 0.20 9.73 0.66 0.00 0.27 0.00 0.22 VOC check g/sec 0.8096 0.5816 0.0228 0.0094 0.0057 0.2799 0.0189 0.0001 0.0078 0.0322 0.0322 VOC TPY total 56.3 1.2 1.6 0.7 0.6 9.7 1.3 0.0 0.5 0.0 0.2 1Notes: a Fuel burned in source, -fuel gas, AFO-arctic fuel oil (No. 2 diesel) b Heaters are dual fuel- fired, a maximum of 100 hours per year on diesel c Shaded cells indicate permit limits (ORL's, BACT limits, PSD avoidance limits)