Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 1 of 46

OREGON DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR CONTAMINANT DISCHARGE PERMIT

Northwest Region

2020 SW 4th Avenue, Suite 400

Portland, OR 97201

(503) 229-5263

Issued in accordance with provisions of ORS 468A.040 

and based on land use compatibility findings included in the permit record.

ISSUED TO: INFORMATION RELIED UPON:

Troutdale Energy Center, LLC Application Number: 027060

11 Martine Avenue, 9th Floor Received: 11/06/2012

White Plains, NY 10606 Additional information 

received: 4/5/2013

PLANT SITE LOCATION: LAND USE COMPATIBILITY STATEMENT:

Troutdale Reynolds Industrial Park, Lot 3 Issued by: See Condition 1

Troutdale, OR 97060 Dated:

ISSUED BY THE DEPARTMENT OF ENVIRONMENTAL QUALITY

____________________________________________ ____________________

David Monro, Northwest Region Air Quality Manager Date

Nature of Business SIC NAICS

Electric Services 4911 221112

FACILITY CONTACT PERSON

Name: Willard Ladd

Title: Manager of Troutdale Energy Center

Phone: 914-468-2400
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 2 of 46

TABLE OF CONTENTS

LIST OF ABBREVIATIONS THAT MAY BE USED IN THIS PERMIT..................................................................3

CONDITIONAL AUTHORIZATION TO CONSTRUCT ...........................................................................................4

PERMITTED ACTIVITIES..........................................................................................................................................4

EMISSIONS UNIT (EU) AND POLLUTION CONTROL DEVICE (PCD) IDENTIFICATION ..............................5

EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECORDKEEPING 

REQUIREMENTS ........................................................................................................................................................6

Facility-wide Requirements.......................................................................................................................................6

Combustion Turbines and Duct Burner (EU1, EU2 and EU3) Requirements...........................................................8

Auxiliary Boiler (EU5) Requirements.....................................................................................................................29

Insignificant Activities Requirements, Including Cooling Towers (EU4) and Fire Pump Engine (EU7) ...............33

PLANT SITE EMISSION LIMITS.............................................................................................................................37

GENERAL TESTING REQUIREMENTS .................................................................................................................41

GENERAL MONITORING AND RECORDKEEPING REQUIREMENTS.............................................................41

REPORTING REQUIREMENTS...............................................................................................................................42

STANDARD ACDP REQUIREMENTS AND General Conditions...........................................................................44
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 3 of 46

LIST OF ABBREVIATIONS THAT MAY BE USED IN THIS PERMIT

ACDP Air Contaminant Discharge Permit

Act Federal Clean Air Act

ASTM American Society of Testing and 

Materials

BACT Best Available Control Technology

Btu British thermal unit

CFR Code of Federal Regulations

CO Carbon monoxide

CO2 Carbon dioxide

CO2e Carbon dioxide equivalent

CPMS Continuous parameter monitoring 

system

DEQ Department of Environmental 

Quality

dscf Dry standard cubic feet

EF Emission factor

EPA US Environmental Protection 

Agency

EU Emissions Unit

FCAA Federal Clean Air Act

FSA Fuel sampling and analysis

GHG greenhouse gas

gr/dscf Grain per dry standard cubic feet (1 

pound = 7000 grains)

HAP Hazardous Air Pollutant as defined 

by OAR 340-244-0040

HCFC Halogenated Chloro-FluoroCarbons

ID Identification number or label

I&M Inspection and maintenance

NA Not applicable

NOx Nitrogen oxides

NSPS New Source Performance Standard

O2 Oxygen

OAR Oregon Administrative Rules

ODEQ Oregon Department of 

Environmental Quality

ORS Oregon Revised Statutes

O&M Operation and maintenance

Pb Lead

PCD Pollution Control Device

PM Particulate matter

PM10 Particulate matter less than 10 

microns in size

PM2.5 Particulate matter less than 2.5 

microns in size

ppm Parts per million

PSEL Plant Site Emission Limit

psia pounds per square inch, actual

SERP Source emissions reduction plan

SO2 Sulfur dioxide

ST Source test

ULSD Ultra-low sulfur distillate 

VE Visible emissions

VMT Vehicle miles traveled

VOC Volatile organic compounds

Modified EPA Method 9: As used in this permit “Modified EPA Method 9” is defined as follows:

Opacity must be measured in accordance with EPA Method 9. For all standards, the minimum observation 

period must be six minutes, though longer periods may be required by a specific rule or permit condition. 

Aggregate times (e.g., 3 minutes in any one hour) consist of the total duration of all readings during the 

observation period that are equal to or greater than the opacity percentage in the standard, whether or not 

the readings are consecutive. Each EPA Method 9 reading represents 15 seconds of time. [See also 

definition of “Opacity” in OAR 340-208-0010]
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 4 of 46

CONDITIONAL AUTHORIZATION TO CONSTRUCT

1. This permit is conditionally issued without a Land Use Compatibility Statement signed by the appropriate 

land use authority pursuant to ORS 469.378. Notwithstanding condition 4, the permittee may not 

commence construction of the permitted facility until such time as one of the conditions in 1.a or 1.b has 

been met, whereupon the permittee is authorized to construct and operate the permitted facility in 

accordance with the plans and specifications in permit application 027060 as amended by this permit.

1.a. A Site Certificate as required by ORS 469.320 has been issued to the permittee for the 

permitted facility by the Oregon Energy Facility Siting Council, established pursuant to ORS 

469.450; or

1.b. A Land Use Compatibility Statement has been signed by the City of Troutdale, Oregon and 

submitted to DEQ.

APPLICATION FOR TITLE V PERMIT

2. The permittee must file a complete application to obtain the Oregon Title V Operating Permit within 12 

months after commencing operation. Commencing operation will be considered initial startup. [340-

218-0040(1)(a)(B)]

PERMITTED ACTIVITIES

3. <reserved, future Title V condition or reference>

4. Approval to construct the facility becomes invalid if construction is not commenced within 18 months 

after this permit takes effect consistent with condition 1, if construction is discontinued for a period of 18 

months or more or if construction is not completed within 18 months of the scheduled time. DEQ may 

extend the 18 month period as allowed by the rules.

5. <reserved, future Title V condition or reference>
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 5 of 46

EMISSIONS UNIT (EU) AND POLLUTION CONTROL DEVICE (PCD) IDENTIFICATION

6. The emissions units regulated by this permit are the following [<reserved, future Title V condition or 

reference>]:

Emissions 

Unit ID

Emissions Unit Description* Emission 

Control 

Device 

ID

Emission Control Device 

Description

EU1 Mitsubishi M501-GAC combustion 

turbine, combined cycle configuration with 

duct burner.

Combustion turbine 2,988 MMBtu/hr, 

natural gas or ULSD

Duct burner 499 MMBtu/hr, natural gas

CCCD1

CCCD2

SCR with aqueous ammonia 

injection for NOx control

Oxidation catalyst for CO, 

VOC control

EU2 GE LMS-100 combustion turbine, simple 

cycle with water injection to reduce NOx 

formation

845 MMBtu/hr, natural gas or ULSD

SC1CD1

SC1CD2

SCR with aqueous ammonia 

injection for NOx control

Oxidation catalyst for CO, 

VOC control

EU3 GE LMS-100 combustion turbine, simple 

cycle with water injection to reduce NOx 

formation

845 MMBtu/hr, natural gas or ULSD

SC2CD1

SC2CD2

SCR with aqueous ammonia 

injection for NOx control

Oxidation catalyst for CO, 

VOC control

EU4 Cooling towers

(categorically insignificant)

NA NA

EU5 Auxiliary boiler, 39.8 MMBtu/hr, natural 

gas, with Low-NOx burners and FGR 

NA NA

EU6 Storage tank, 2.2 million gallons, fixed 

roof, ULSD (vapor pressure 0.0055 psia)

NA NA

EU7 Emergency fire water pump powered by 

360 hp CI RICE, ULSD

(categorically insignificant)

NA NA

 * All heat values are based on higher heating value (HHV)
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 6 of 46

EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECORDKEEPING 

REQUIREMENTS

The following tables and conditions contain the applicable requirements along with testing, monitoring, and 

recordkeeping requirements for the emissions units to which those requirements apply.

Facility-wide Requirements

Applicable 

Requirement

Condition 

Number

Pollutant/ 

Parameter Limit/Standard

Testing 

Condition

Monitoring 

Condition

340-208-0210(2) 7 Fugitive 

emissions

minimize NA 8

340-208-0300 9 Nuisance no nuisance NA 11

340-208-0450 10 PM >250m no fallout NA 11

owner requested 

limitation

12 Fuels natural gas and 

ULSD (15 ppm

sulfur maximum)

NA 37

40 CFR Part 68 13 Risk 

management

Risk management 

plan

NA 13

7. Applicable Requirement The permittee must not allow or permit any materials to be handled, 

transported, or stored; or a building, its appurtenances, or a road to be used, constructed, altered, repaired 

or demolished; or any equipment to be operated, without taking reasonable precautions to prevent 

particulate matter from becoming airborne. Such reasonable precautions must include, but not be limited 

to the following: [OAR 340-208-0210(2)]

7.a. use, where possible, of water or chemicals for control of dust in the demolition of existing 

buildings or structures, construction operations, the grading of roads or the clearing of land;

7.b. application of asphalt1, oil, water, or other suitable chemicals on unpaved roads, materials 

stockpiles, and other surfaces which can create airborne dusts;

7.c. full or partial enclosure of materials stockpiles in cases where application of oil, water, or 

chemicals are not sufficient to prevent particulate matter from becoming airborne;

7.d. installation and use of hoods, fans, and fabric filters to enclose and vent the handling of 

dusty materials;

7.e. adequate containment during sandblasting or other similar operations; and

7.f. covering, at all times when in motion, open bodied trucks transporting materials likely to 

become airborne.

8. Monitoring Requirement At least once month, the permittee must visually survey the plant for any 

sources of excess fugitive emissions. For the purpose of this survey, excess fugitive emissions are 

considered to be any visible emissions that leave the plant site boundaries. The person conducting the 

observation does not have to be EPA Method 9 certified. However, the individual should be familiar with 

the procedures of EPA Method 9, including using the proper location to observe visible emissions. If 

sources of visible emissions are identified, the permittee must: [<reserved, future Title V condition or 

reference>]

 

1 Although specified in the rules, DEQ discourages the use of asphalt and oil as dust suppressants because of the 

negative environmental impact on other media.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 7 of 46

8.a. Immediately take corrective action to minimize the fugitive emissions, including but not 

limited to those actions identified in condition 7; or

8.b. Conduct a Modified EPA Method 9 (see page 2 of the permit) test within 24 hours.

8.c. Recordkeeping The permittee must maintain records of the fugitive emissions surveys, 

corrective actions (if necessary), and/or the results of any modified EPA Method 9 tests.

Nuisance Conditions

9. Applicable Requirement The permittee must not cause or allow air contaminants from any source to 

cause a nuisance. Nuisance conditions will be verified by Department personnel. [OAR 340-208-0300] 

This condition is enforceable only by the State.

10. Applicable Requirement The permittee must not cause or permit the emission of any particulate matter 

larger than 250 microns in size at sufficient duration or quantity, as to create an observable deposition 

upon the real property of another person. DEQ will verify that the deposition exists and will notify the 

permittee that the deposition must be controlled. [OAR 340-208-0450] 

This condition is enforceable only by the State.

11. Monitoring Requirement The permittee must maintain a log of each nuisance complaint received by the 

permittee during the operation of the facility. Documentation must include date of contact, time of 

observed nuisance condition, description of nuisance condition, location of receptor, status of plant 

operation during the observed period, and time of response to complainant. A plant representative must 

immediately investigate the condition following the receipt of the nuisance complaint and a plant 

representative must provide a response to the complainant within 24 hours, if possible. [<reserved, future 

Title V condition or reference>] 

This condition is only enforceable by the state.

Fuels

12. Applicable Requirement The permittee must not burn any fuel other than natural gas, or ultra-low sulfur 

distillate (ULSD) fuel containing not more than 15 ppm sulfur. [owner requested fuels limitation; this 

condition is in lieu of OAR 340-228-0110] 

Compliance with this requirement must be monitored in accordance with conditions 17, 31, 37 and 59.

Part 68 Risk Management Plan

13. Applicable Requirement Should this stationary source become subject to the accidental release 

prevention regulations in 40 CFR Part 68, then the permittee must submit a risk management plan (RMP) 

by the date specified in 40 CFR 68.10 and comply with the plan and all other applicable Part 68 

requirements. [40 CFR Part 68]
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 8 of 46

Combustion Turbines and Duct Burner (EU1, EU2 and EU3) Requirements

Applicable 

Requirement

Condition 

Number

Pollutant/ 

Parameter Limit/Standard

Monitoring 

Condition

Testing 

Condition

OAR 340-208-0110

14

Visible

emissions

20% opacity 17, 18 NA

OAR 340-208-0600

15

Visible

emissions

20% opacity 17, 18 NA

OAR 340-226-

0210(1)(b)

16 PM (non-fuel 

burning 

equipment)

0.1 gr/dscf 

@12%CO2

17, 18 NA

OAR 340-228-

0210(1)(b)

16 PM (fuel 

burning 

equipment)

0.1 gr/dscf 

@12%CO2

17, 18 NA

BACT

(OAR 340-224-0070)

19 Allowed fuels Natural gas & 

ULSD 

31 NA

BACT

(OAR 340-224-0070)

20 PM EU1: 23.6 lb/hr 

(gas) & 42.3 

lb/hr (ULSD)

EU2 & 3: 9.1 

lb/hr (gas) & 

22.7 lb/hr

(ULSD)

NA 50

BACT

(OAR 340-224-0070)

21 NOx EU1: 2.0 ppmdv

(gas) & 5.5 

ppmdv (ULSD)

EU2 & 3: 2.5 

ppmdv (gas) & 

3.8 ppmdv

(ULSD)

40, 42 48

BACT

(OAR 340-224-0070)

22 CO EU1: 3.3 ppmdv

(gas) & 9.0 

ppmdv (ULSD)

EU2 & 3: 6.0 

ppmdv (gas & 

ULSD)

41 41

BACT

(OAR 340-224-0070)

23 VOC EU1: 2.0 ppmdv

(gas) & 5.0 

ppmdv (ULSD)

EU2 & 3: 3.5 

ppmdv (gas) & 

5.0 ppmdv

(ULSD)

NA 50
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 9 of 46

Applicable 

Requirement

Condition 

Number

Pollutant/ 

Parameter Limit/Standard

Monitoring 

Condition

Testing 

Condition

BACT

(OAR 340-224-0070)

24 CO2 EU1: 1000 

lb/MWh

EU2 & 3: 1707 

lb/MWh

47 NA

BACT

(OAR 340-224-0070)

26 H2SO4 Natural gas & 

ULSD

17 NA

BACT

(OAR 340-224-0070)

27 Startup/

Shutdown

Time limits 35 NA

Owner requested 

limitation,

OAR 340-226-0120(1)

29 Operating 

mode, EU1

Duct firing 

prohibited when 

ULSD is used in 

EU1 

31 NA

Owner requested 

limitation,

OAR 340-226-0120(1)

30 Operating 

mode, EU1

ULSD fuel 

usage limited to 

up to 720 hours 

per calendar year 

during periods of 

natural gas 

curtailment 

31

NA

Owner requested 

limitation,

OAR 340-226-0120(1)

30 Operating 

Mode, EU2

and EU3

ULSD fuel 

usage limited to 

up to 720 hours 

per calendar year 

during periods of 

natural gas 

curtailment 

31

NA

Owner requested 

limitation,

OAR 340-226-0120(1)

32 Ammonia 

slip

5 ppmdv 33 49

40 CFR 60.4333, 

Subpart KKKK

34 O&M See condition 35 NA

40 CFR Part 60, 

Subpart KKKK

OAR 340-238-

0060(3)(bbbb)

36 SO2 20 grains per 

100 standard 

cubic feet

37, 46 NA

40 CFR Part 60, 

Subpart KKKK

OAR 340-238-

0060(3)(bbbb)

38, 39 NOX emission

concentration 

or mass limit

EU1: 15 ppmdv

(gas) & 42

ppmdv (ULSD)

EU2 & 3: 15 

ppmdv (gas) & 

42 ppmdv

(ULSD)

40, 42 48
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 10 of 46

Applicable 

Requirement

Condition 

Number

Pollutant/ 

Parameter Limit/Standard

Monitoring 

Condition

Testing 

Condition

40 CFR Part 60, 

Subpart KKKK or 

TTTT, as applicable

44 See Subpart 

KKKK or 

TTTT

See Subpart 

KKKK or TTTT

NA NA

40 CFR 60.4375 43 NOx Excess emission 

reporting

NA NA

40 CFR 75.10(c) 45 Heat input Monitor 46, 47 NA

Opacity and Particulate Matter Requirements

14. Applicable Requirement The permittee must not cause or allow the emissions of any air contaminant 

into the atmosphere from EU1, EU2 or EU3 for a period or periods aggregating more than three minutes 

in any one hour which is equal to or greater than 20% opacity, excluding uncombined water. [OAR 340-

208-0110(2) and 340-208-0110(3)]. 

Monitor in accordance with conditions 17 and 18.

15. Applicable Requirement The permittee must not cause or allow EU1, EU2 or EU3 to discharge any air 

contaminant that is 20 percent opacity or greater into the atmosphere for a period of or periods totaling 

more than 30 seconds in any one hour. This condition does not apply to EU1 when the duct burner is 

operating. [OAR 340-208-0600]

Monitor in accordance with conditions 17 and 18.

16. Applicable Requirement The permittee must not cause or allow the emissions of particulate matter 

from EU1, EU2 or EU3 in excess of 0.1 grains per dry standard cubic foot. [OAR 340-226-0210(1)(b)

(non-fuel burning equipment) and OAR 340-228-0210(1)(b) (fuel burning equipment)]. 

Monitor in accordance with conditions 17 and 18, and test in accordance with condition 51.

17. Monitoring for Conditions 14, 15and 16. At any time that the permittee is burning natural gas in 

emission unit EU1, EU2 or EU3, the permittee is not required to conduct any visible emissions or 

particulate matter monitoring for that unit because it is extremely unlikely that the standard set forth in 

Condition 14 could be exceeded when the unit is burning natural gas. The permittee must maintain daily 

and annual records of the type of fuel being burned in emissions units EU1, EU2 and EU3 in accordance 

with condition 31. If visible emissions are to be measured for any reason, the visible emissions must be 

measured in accordance with the Department’s Source Sampling Manual. 

18. Monitoring for Conditions 14, 15 and 16. When using ULSD in combustion turbines EU1, EU2 or 

EU3, the permittee must monitor visible emissions from the emissions unit(s) using ULSD in accordance 

with the following:

18.a. On any calendar day where a combustion turbine is operated on ULSD fuel for more than 60 

minutes during daylight hours, the permittee must conduct an EPA Method 22 test for a 

minimum period of six minutes during normal operations. If, during the EPA Method 22 test 

visible emissions are detected for more than 5% of the observation period (i.e. 2 or more 

readings representing 15 seconds each in a 6 minute period), the permittee must conduct a 

modified EPA Method 9 test within 24 hours.

18.b. If 7 consecutive days of EPA Method 22 tests show no visible emissions or the modified 

EPA Method 9 test results are less than the applicable standard in Condition 14, the test 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 11 of 46

frequency may be weekly. 

18.c. The modified EPA Method 9 test must be a minimum of 6 minutes long unless any one 

reading is greater than 20% opacity, then the observation period must be 60 minutes or until 

a violation of the applicable standard in Condition 14 is documented, whichever period is 

shorter. Each modified EPA Method 9 observation must represent 15 seconds for the 

purpose of determining the aggregate amount of time in a 60 minute period that the visible 

emissions are greater than 20% opacity. [<reserved, future Title V condition or reference>] 

18.d. If any test result exceeds the standard in Condition 14, the permittee must take corrective 

action and the test frequency must be daily for 5 consecutive days following the exceedance. 

If the results of the daily tests are all less than the standard in Condition 14, the test 

frequency must be the same as before the exceedance occurred. 

18.e. If, on a regularly scheduled test day, it is not possible to conduct an EPA Method 22 or 

modified EPA Method 9 test due to inclement weather conditions or interference from other 

fugitive sources, the permittee must make three attempts during the day at approximately 10 

a.m., noon, and 2 p.m. If it is still not possible to conduct the test, the permittee must 

perform the test the following day. The permittee must record in a log the reason for not 

conducting the test on a regularly scheduled test day. 

18.f. Recordkeeping Requirement The permittee must keep the following records:

18.f.i. the date and time of each visible emission observation;

18.f.ii. the identification of the emissions unit(s) observed;

18.f.iii. the results of the visible emissions observation;

18.f.iv. the reason for not conducting a test on a regularly scheduled day; and

18.f.v. any corrective actions taken.

BACT Requirements [OAR 340-224-0070] 

19. Applicable Requirement The permit must use only natural gas and ULSD in emissions units EU1, EU2 

and EU3. [NSR/PSD permit 26-0235 BACT] 

Monitor in accordance with condition 31.

20. Applicable Requirement: The permittee must not cause or allow the emissions of Particulate Matter 

(PM), PM10 or PM2.5 from each combustion turbine stack to exceed: [NSR/PSD permit 26-0235 

BACT]

20.a. For EU1, 23.6 lb/hr while burning natural gas, and 42.3 lb/hr while burning ULSD; 6-hour rolling 

average. 

20.b. For EU2 and EU3, 9.1 lb/hr while burning natural gas, and 22.7 lb/hr while burning ULSD; 6-hour 

rolling average. 

20.c. These limits do not apply during periods of startup and shutdown.

Test in accordance with condition 51.

21. Applicable Requirement: The permittee must not cause or allow the emissions of nitrogen oxides (NOx) 

from each combustion turbine stack to exceed: [NSR/PSD permit 26-0235 BACT]

21.a. For EU1, 2.0 ppmdv while burning natural gas, and 5.5 ppmdv while burning ULSD; 

corrected to 15% oxygen, 3-hour rolling average.

21.b. For EU2 and EU3, 2.5 ppmdv while burning natural gas, and 3.8 ppmdv while burning 

ULSD; corrected to 15% oxygen, 3-hour rolling average.

21.c. These limits do not apply during periods of startup and shutdown.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 12 of 46

Monitor in accordance with condition 40 and test in accordance with condition 48.

22. Applicable Requirement: The permittee must not cause or allow the emissions of carbon monoxide (CO) 

from each combustion turbine stack to exceed: [NSR/PSD permit 26-0235 BACT]

22.a. For EU1, 3.3 ppmdv while burning natural gas, and 9.0 ppmdv while burning ULSD; 

corrected to 15% oxygen, 3-hour rolling average.

22.b. For EU2 and EU3, 6.0 ppmdv while burning natural gas, and 6.0 ppmdv while burning 

ULSD; corrected to 15% oxygen, 3-hour rolling average.

22.c. These limits do not apply during periods of startup and shutdown.

Monitor in accordance with condition 41 and test in accordance with condition 48.

23. Applicable Requirement: The permittee must not cause or allow the emissions of total volatile organic 

compounds (VOC, reported as methane) from each combustion turbine stack to exceed: [NSR/PSD 

permit 26-0235 BACT]

23.a. For EU1, 2.0 ppmdv while burning natural gas, and 5.0 ppmdv while burning ULSD; 3-hour 

rolling average.

23.b. For EU2 and EU3, 3.5 ppmdv while burning natural gas, and 5.0 ppmdv while burning 

ULSD; 3-hour rolling average.

23.c. Compliance with these limits must be demonstrated by a performance test as detailed in 

condition 50.

23.d. These limits apply to each emission unit after the initial performance test specified in 

condition 50.

23.e. These limits do not apply during periods of startup or shutdown.

Test in accordance with condition 47.

24. Applicable Requirement: The permittee must not cause or allow the emissions of carbon dioxide (CO2) 

from each combustion turbine stack to exceed: [NSR/PSD permit 26-0235 BACT]

24.a. For EU1, 1000 lb/MWh (gross), 365 day rolling average.

24.b. For EU2 and EU3, 1707 lb/MWh (gross), 365 day rolling average.

24.c. These limits apply at all times, including during periods of startup and shutdown.

Monitor in accordance with condition 25.

25. Monitoring and Recordkeeping Requirement The permittee must monitor GHG emissions from 

combustion turbines EU1, EU2 and EU3 in accordance with the following:

25.a. Install, maintain and operate a CO2 CEMS in accordance with 40 CFR Part 60, Appendix B, 

Performance Specification 3 (PS3);

25.b. Monitor the daily MWh (gross) produced by each combustion turbine (Note: MWh (gross) 

means the total power output prior to any parasitic load, and includes the output from the 

steam turbine generator);

25.c. Calculate the daily pounds of CO2 per MWh (gross) from combustion turbines EU1, EU2 

and EU3; and

25.d. Calculate the 365 day rolling average pounds of CO2 per MWh from the daily emissions.

26. Applicable Requirement: The permittee must control emissions of sulfuric acid mist (H2SO4) from 

emission units EU1 through EU3 by utilizing good combustion practices and only combusting natural gas 

and ULSD. [NSR/PSD permit 26-0235 BACT]

Monitor in accordance with condition 31.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 13 of 46

27. Applicable Requirement: The permittee must limit the time counted as startup or shutdown in accordance 

with this condition. [NSR/PSD permit 26-0235 BACT]

27.a. Exceeding the startup and shutdown times specified in conditions 27.d and 27.e is not a 

violation of this condition unless the permittee simultaneously fails to comply with condition 

27.b or condition 27.c.

27.b. Commencing the next minute after the allowed startup or shutdown time specified in this 

condition, the permittee must consider the emissions in determining compliance with 

conditions 21 and 22.

27.c. All minutes of startup or shutdown, including any minutes that exceed the limits in 

conditions 27.d.i through 27.d.iv, 27.e.i and 27.e.ii, must be counted toward compliance with 

the rolling 12-month limits on total hours of startup or shutdown specified in conditions 27.d

and 27.e.

27.d. For EU1,

27.d.i. Individual2cold starts must not exceed 4.5 hours;

27.d.ii. Individual warm starts must not exceed 1.5 hours;

27.d.iii. Individual hot starts must not exceed 1.0 hours; 

27.d.iv. Individual shutdowns must not exceed 15 minutes;

27.d.v. Total3startup time must not exceed 304 hours in any rolling 12 month period; and

27.d.vi. Total shutdown time must not exceed 17 hours in any rolling 12 month period.

27.e. For EU2 and EU3,

27.e.i. Individual2startups must not exceed 10 minutes per turbine;

27.e.ii. Individual shutdowns must not exceed 11 minutes per turbine;

27.e.iii. Total3startup time must not exceed 167 hours per turbine in any rolling 12 month 

period; and

27.e.iv. Total shutdown time must not exceed 163 hours per turbine in any rolling 12 month 

period.

27.f. For the purpose of this condition, the following definitions apply:

27.f.i. “Hot start” means starting of a combustion turbine when less than 18 hours have 

passed since the unit finished being shut down, or the unit was restarted before the 

shutdown sequence was completed;

27.f.ii. “Warm start” means starting of a combustion turbine when between 18 hours and 48 

hours have passed since the unit finished being shut down;

27.f.iii. “Cold start” means starting of a combustion turbine when more than 48 hours have 

passed since the unit finished being shut down;

27.f.iv. “Startup” means the period commencing when fuel is first fired in the combustion 

turbine after the unit has been shut down and ending when operations have stabilized; 

and

27.f.v. “Shutdown” means the period commencing when normal operations cease and ending 

when fuel is no longer being supplied to the unit.

Monitor in accordance with condition 28.

 

2

Individual startup and shutdown times are worst case times.

3 Total startup and shutdown times are based on expected actual average times for starts/stops, not worst case times.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 14 of 46

28. Monitoring and Recordkeeping Requirement The permittee must monitor and record the following for 

EU1, EU2 and EU3 (combustion turbines):

28.a. The duration of each individual startup;

28.b. The duration of each individual shutdown;

28.c. The number and type (cold, warm, hot) of startups each month;

28.d. The number of shutdowns each month;

28.e. The total startup time in each rolling 12 month period; and

28.f. The total shutdown time in each rolling 12 month period.

Owner Requested Limitations

29. Applicable Requirement: The duct burners (EU1) must burn only natural gas and may not be fired when 

ULSD is being combusted in the EU1 combustion turbine. [OAR 340-226-0120(1)]

Monitor in accordance with condition 31.

30. Applicable Requirement: The combustion turbines must burn only natural gas except as follows: [OAR 

340-226-0120(1)]

30.a. All combustion turbines (EU1, EU2 and EU3) may burn ULSD fuel for the purpose of 

commissioning, equipment maintenance and testing, and emissions source testing. Such use 

must be held to the minimum amount required to accomplish the activity.

30.b. All combustion turbines (EU1, EU2 and EU3) may burn ULSD fuel in the event of natural 

gas curtailment, not to exceed 720 hours per turbine per calendar year.

30.b.i. For the purpose of this permit condition, curtailment means actual or effective 

deliverability events related to either natural gas commodity supply or transportation 

curtailment.

30.b.ii. Actual or effective deliverability events may be demonstrated by keeping records of 

announcements by gas suppliers, gas transporters, or government entities; or by 

keeping records demonstrating extreme price volatility in day to day spot prices for 

the gas pipeline that supplies the facility.

Monitor in accordance with condition 31.

31. Monitoring and Recordkeeping Requirement The permittee must monitor and record the following with 

respect to fuel usage in in emissions units EU1 (combustion turbine and duct burner), and EU2 and EU3 

(combustion turbines):

31.a. The type and amount of fuel used in each combustion turbine, on an hourly basis.

31.b. The type and amount fuel used in the EU1 duct burner, on an hourly basis.

31.c. The start and stop times and the duration of each period of ULSD use in each turbine.

31.d. The total hours per calendar year that ULSD fuel is used in each turbine.

31.e. The reasons for using ULSD.

31.f. Whenever the reason for using ULSD is curtailment:

31.f.i. Keep records of announcements by gas suppliers, gas transporters, or government 

entities; or

31.f.ii. Keep records demonstrating extreme price volatility in day to day spot prices for the 

gas pipeline that supplies the facility.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 15 of 46

32. Applicable Requirement: The permittee must limit ammonia slip as follows: [OAR 340-226-0120(1)]

32.a. From EU1, to no more than 5 ppmdv at 15 percent O2 based upon a 3-hour block average.

32.b. From EU2 and EU3, to no more than 5 ppmdv at 15 percent O2 based upon a 3-hour block

average.

Monitor in accordance with condition 33 and test in accordance with condition 49.

33. Monitoring and Recordkeeping Requirement The permittee must monitor and record the amount of 

ammonia injected into emissions units EU1, EU2 and EU3 (combustion turbines).
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 16 of 46

NSPS Subpart KKKK

34. Applicable Requirement: The permittee must operate and maintain EU1 (combined-cycle combustion 

turbine) and simple-cycle combustion turbines EU2 and EU3, the associated air pollution control 

equipment, and the associated monitoring equipment in a manner consistent with good air pollution 

control practices for minimizing emissions at all times including during startup, shutdown, and 

malfunction. [40 CFR 60.4333]

Monitor in accordance with condition 35.

35. Monitoring and Recordkeeping Requirement: The permittee must keep the following records for EU1 

through EU3:

35.a. Records of the occurrence and duration of any startup, shutdown, or malfunction in the 

operation of EU1 through EU3; [40 CFR 60.7(b)]

NSPS KKKK SO2

36. Applicable Requirement The permittee must meet one of the following emission limits for SO2 from 

EU1 (combined-cycle combustion turbine) and EU2 and EU3 (simple-cycle combustion turbines): [40 

CFR 60.4330(a)(1) and (2)]

36.a. Do not cause to be discharged into the atmosphere any gases which contain SO2 in excess of 

110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour (lb/MWh)) gross output; or

36.b. Do not burn any fuel which contains total potential sulfur emissions in excess of 26 ng SO2

/J (0.060 lb SO2 /MMBtu) heat input.

Monitor in accordance with condition 37.

37. Monitoring Requirement The permittee must either monitor the total sulfur content of the fuel used in 

units EU1, EU2 and EU3 as provided in 40 CFR 60.4360 or it must demonstrate the fuel does not exceed 

potential sulfur emissions of 26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input. 

37.a. If the permittee selects the monitoring option, monitoring of fuel sulfur content must be done

in accordance with the fuel sampling provisions in section 2.3.1.4 or 2.3.2.4 of appendix D 

to part 75. For ULSD, the permittee must use one of the total sulfur sampling options and the 

associated sampling frequency described in sections 2.2.3, 2.2.4.1, 2.2.4.2, and 2.2.4.3 of 

appendix D to 40 CFR Part 75 (i.e., flow proportional sampling, daily sampling, sampling 

from the unit’s storage tank after each addition of fuel to the tank, or sampling each delivery 

prior to combining it with ULSD already in the intended storage tank). If an emission 

allowance is being claimed for fuel-bound nitrogen, the nitrogen content of the ULSD must 

be determined and recorded once per unit operating day. [40 CFR 60.4370(a)]

37.b. If the permittee selects the demonstration option, it must use one of the following sources of 

information to make the demonstration for each fuel type used in the turbines: [40 CFR 

60.4365]

37.b.i. The permittee may refer to the fuel quality characteristics in a current, valid purchase 

contract, tariff sheet or transportation contract for the fuel, specifying that:

37.b.i.A. the maximum total sulfur content in the ULSD used in the turbines 

is 0.05 weight percent (500 ppmw) or less, and

37.b.i.B. the total sulfur content for natural gas used is 20 grains of sulfur or 

less per 100 standard cubic feet.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 17 of 46

NSPS KKKK NOx

38. Applicable Requirement The permittee must meet the following emission limits for NOx from EU1 

(combined-cycle combustion turbine) on a 30 unit operating day rolling average basis: [40 CFR 60.4320, 

Table 1, 60.4325, and 60.4380(b)(1)]

38.a. 15 ppm at 15 percent O2 or 54 ng/J of useful output (0.43 lb/MWh) while combusting 

natural gas;

38.b. 42 ppm at 15 percent O2 or 160 ng/J of useful output (1.3 lb/MWh) while combusting 

ULSD; and

38.c. these limits do not apply during periods of startup, shutdown or malfunction. [40 CFR 

60.8(c)]

Monitor in accordance with conditions 40, 41 and 42; and test in accordance with condition 48.

39. Applicable Requirement The permittee must meet the following emission limits for NOx from EU2 and 

EU3 (simple-cycle combustion turbines) on a 4-hour rolling average basis: [40 CFR 60.4320, Table 1, 

60.4325, and 60.4380(b)(1)]

39.a. 15 ppm at 15 percent O2 or 54 ng/J of useful output (0.43 lb/MWh) while combusting 

natural gas;

39.b. 42 ppm at 15 percent O2 or 160 ng/J of useful output (1.3 lb/MWh) while combusting 

ULSD; and

39.c. these limits do not apply during periods of startup, shutdown or malfunction. [40 CFR 

60.8(c)]

Monitor in accordance with conditions 40, 41 and 42; and test in accordance with condition 48.

40. Monitoring Requirement The permittee must install, certify, maintain, and operate a continuous emission 

monitoring system (CEMS) for NOx on EU1 (combined-cycle combustion turbine) and EU2 and EU3 

(simple-cycle combustion turbines) in accordance with this condition:

40.a. The CEMS must consist of a NOx monitor and a diluent gas (oxygen (O2)) or carbon dioxide 

(CO2)) monitor, to determine:

40.a.i. Hourly NOx emission rate in parts per million (ppm), and 

40.a.ii. Either pounds per million British thermal units (lb/MMBtu) or pounds per megawatthour (lb/MWh), and 

40.a.iii. Mass emission rate (lb/hr) discharged to the atmosphere in accordance with 40 CFR 

75.10(a)(2) and 75.12. 

In case of a conflict between the conditions in this permit and 40 CFR Part 75, the requirements of 

40 CFR Part 75 must be followed. [40 CFR 60.4335(b) and 60.4340(b)(1)]

Turbines Pollutant Units Averaging Time

All Turbines Oxygen Percent 1 Hour Average

EU1 Nitrogen Oxides (NOx)

ppmdv at 15% O2,

lb/MMBtu,

lb/MWH, and

lb/hr

30 Day Rolling*

EU2 and EU3 Nitrogen Oxides (NOx)

ppmdv at 15% O2,

lb/MMBtu, and

lb/hr

4 Hours Rolling*

* Note: The rolling averages do not apply during periods of startup and shutdown. [40 CFR 60.8(c)]
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 18 of 46

40.b. The NOx CEMS must meet the following requirements: [40 CFR 60.4345]

40.b.i. Each NOx diluent CEMS must be installed and certified according to Performance 

Specification 2 (PS 2) in appendix B to 40 CFR Part 60, except the 7-day calibration 

drift is based on unit operating days, not calendar days. With state approval,

Procedure 1 in appendix F to 40 CFR Part 60 is not required. Alternatively, a NOx 

diluent CEMS that is installed and certified according to appendix A of 40 CFR Part 

75 is acceptable for use under this subpart. The relative accuracy test audit (RATA) of 

the CEMS must be performed on a lb/MMBtu basis.

40.b.ii. As specified in 40 CFR 60.13(e)(2), during each full unit operating hour, both the 

NOX monitor and the diluent monitor must complete a minimum of one cycle of 

operation (sampling, analyzing, and data recording) for each 15-minute quadrant of 

the hour, to validate the hour. For partial unit operating hours, at least one valid data 

point must be obtained with each monitor for each quadrant of the hour in which the 

unit operates. For unit operating hours in which required quality assurance and 

maintenance activities are performed on the CEMS, a minimum of two valid data 

points (one in each of two quadrants) are required for each monitor to validate the 

NOX emission rate for the hour.

40.b.iii. The NOx concentration corrected to 15% oxygen must be calculated for all turbines as 

follows:

CCNOx = CNOx x 5.9/(20.9 - %O2)

Where:

CCNOx = Hourly average NOx concentration, ppm (corrected)

CNOx = Hourly average NOx concentration, ppm (uncorrected)

%O2 = Hourly average %O2 by volume in flue gas

40.b.iv. The mass emissions rate in pounds per hour must be calculated for all turbines as 

follows:

MNOx = ERNOx x HIg

Where:

MNOx = Hourly mass of NOx emissions, lb/hr.

ERNOx = NOx emission rate in lb/MMBtu as measured by the CEMS

HIg = Hourly heat input as determined in accordance with Condition 45 and 

equation D-15a in appendix D of 40 CFR Part 75

40.b.v. The emission rate in pounds per megawatt-hour must be calculated for the turbines if 

complying with the output based standard, as follows: [40 CFR 60.4350(f)]

E = (NOx)h * (HI)h/P

Where:

E = Hourly NOX emission rate, in lb/MWh

(NOX)h = Hourly NOX emission rate, in lb/MMBtu

(HI)h = Hourly heat input as determined in accordance with Condition 45

and equation D-15a in appendix D of 40 CFR Part 75, and

P = (Pe)t+ (Pe)c + PS + Po
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 19 of 46

Where:

P = Gross energy output of the stationary combustion turbine system in 

MW

(Pe)t = Electrical or mechanical energy output of the combustion turbine 

in MW

(Pe)c = Electrical or mechanical energy output (if any) of the steam turbine 

in MW, and

Ps = Q * H/3.413 x 106 Btu/MWh

Where:

Ps = Useful thermal energy of the steam, measured relative to ISO 

conditions, not used to generate additional electric or mechanical 

output, in MW

Q = Measured steam flow rate in lb/h

H = Enthalpy of the steam at measured temperature and pressure relative 

to ISO conditions, in Btu/lb, and 3.413 x 106 = conversion from Btu/h to 

MW

Po = Other useful heat recovery, measured relative to ISO conditions, 

not used for steam generation or performance enhancement of the 

combustion turbine

40.b.vi. The permittee must ensure that all NOx CEMS meet the equipment, installation and 

performance specifications in 40 CFR Part 75 Appendix A. [40 CFR 75.10(b)]

40.b.vii. The permittee must ensure that all NOx CEMS are in operation at all times that the 

combustion turbines combust any fuel and that the following requirements are met: 

[40 CFR 75.10(d)] 

40.b.vii.A. The permittee must ensure that each NOx CEMS and component 

thereof is capable of completing a minimum of one cycle of 

operation (sampling, analyzing and data recording) for each 

successive 15-minute interval. The permittee must reduce all NOx

concentration and NOx emissions rate data to 1-hour averages. The 

permittee must compute these averages from four or more data 

points collected in each of four successive 15-minute periods 

(minimum of 4 data points per hour), except during periods when 

calibration, quality assurance, or maintenance activities pursuant to 

40 CFR 75.21 and appendix B of 40 CFR Part 75 are being 

performed. During these periods, a valid hour consists of at least 

two data points separated by a minimum of 15 minutes. For 

combined monitoring systems (NOx - diluent), the hourly average 

emission rate is valid only if the hourly average concentration from 

each of the component monitors is valid.

40.b.vii.B. Failure of a NOx CEMS to acquire the minimum number of data 

points comprising a valid hour, as specified in this condition, will 

result in the loss of such component data for the entire hour. The 

permittee must estimate and record emission or flow data for the 

missing hour by means of the automated DAHS, in accordance with 

40 CFR Part 75, Subpart D.

40.c. The permittee must develop and keep on-site a quality assurance (QA) plan for all of the 

continuous monitoring equipment described in this permit condition. For the CEMS and fuel 

flow meters, the permittee may, with DEQ approval, satisfy the requirements of this 

paragraph by implementing the QA program and plan described in section 1 of appendix B 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 20 of 46

to 40 CFR Part 75.

41. Monitoring and Recordkeeping Requirement The permittee must calibrate, maintain and operate 

continuous emissions monitors in the turbine systems for CO and O2, and record the associated emissions 

according to the units and averaging times below. The continuous monitoring systems must, at a 

minimum, conform with the Department’s Continuous Monitoring Manual (Jan. 1992). The main 

elements of the Continuous Monitoring Manual include the development and submittal of Standard 

Operating Procedures, a Quality Assurance Plan, and conducting Relative Accuracy Test Audits.

Turbines Pollutant Units Averaging Time

All Turbines Oxygen Percent 1 Hour Average

All Turbines Carbon Monoxide ppmdv at 15% O2 and lb/hr 3 Hours Rolling*

Note *: The rolling averages do not apply during periods of startup and shutdown. [NSR/PSD permit 26-

0235 BACT]

41.a. The CO concentration in the emissions from the combustion turbines/duct burners corrected 

to 15% oxygen must be calculated and recorded each clock hour that the combustion 

turbines are operating using the following equation: 

CCCO = CCO x (20.9 – 15)/(20.9 - %O2)

Where:

CCCO = Hourly average CO concentration, ppm (corrected to 15% O2)

CCO = Hourly average CO concentration, ppm (uncorrected)

15 = Oxygen correction level (%)

%O2 = Actual stack gas oxygen concentration (%) measured by the oxygen

CEMS

41.b. Mass emissions of CO from the combustion turbines/duct burners must be recorded each 

clock hour that the combustion turbines are operating using the following equation:

Mco = Cco/106x MWco/385 x Fd x 20.9/(20.9-%O2) x HI

Where:

Mco = Hourly mass of CO emissions, lb/hr

Cco = Hourly average CO concentration, ppm (uncorrected)

1/106= Conversion from ppm to a fraction

MWco = Molecular weight of CO = 28 lb/lb-mole

385 = Dry standard cubic feet per lb-mole at 14.7 psia and 68°F

Fd = Dry fuel factor = 8710 dscf/MMBtu for natural gas, 9190 dscf/MMBtu

for oil [EPA Method 19]

%O2 = Actual stack gas oxygen concentration (%) measured by the oxygen

CEMS

HI = Hourly heat input = cubic feet of natural gas burned times the most 

recent heating value. (HI is in units of MMBtu/hr)

41.c. The CO concentration in parts per million, corrected to 15% oxygen and emission rate (lb/hr) 

must also be recorded as a 3-hour rolling average. At the end of each clock hour, a new 3-

hour average is calculated and recorded using all available hourly averages during the 

previous 3-hour period, excluding periods of startup and shutdown.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 21 of 46

42. Monitoring Requirement The permittee must continuously monitor the emissions of NOx from EU1 

(combined-cycle combustion turbine) and EU2 and EU3 (simple-cycle combustion turbines) using the 

NOx CEMS required by condition 40, and in accordance with this condition. [40 CFR 60.4335, 4340 and 

4350]

42.a. All CEMS data must be reduced to hourly averages (clock hours).

42.b. Calculate the hourly average NOx emission rates in accordance with the following:

42.b.i. Calculate emission rates in the following units: [40 CFR 60.4350(f)]

42.b.i.A. parts per million (ppmdv), uncorrected;

42.b.i.B. parts per million (ppmdv), corrected to 15 percent oxygen;

42.b.i.C. pounds per hour (lb/hr);

42.b.i.D. pounds per million Btu (lb/MMBtu); and

42.b.i.E. pounds per megawatt-hour (lb/MWh), if applicable.

42.b.ii. Use the appropriate equation from method 19 in appendix A of 40 CFR Part 60.

42.b.iii. For any hour in which the hourly average O2 concentration exceeds 19.0 percent O2, 

a diluent cap value of 19.0 percent O2 may be used in the emission calculations.

42.c. For EU2 and EU3 (simple-cycle combustion turbines), use the calculated hourly average 

emission rates to calculate emissions in ppmdv or lb/MWh on a 4-hour rolling average basis. 

[40 CFR 60.4350(g)]

42.d. For EU1 (combined-cycle combustion turbine), use the calculated hourly average emission 

rates to calculate emissions in ppmdv or lb/MWh on a 30 unit operating day rolling average 

basis. [40 CFR 60.4350(h)]

42.e. Hours with startups, shutdowns or malfunctions are not counted for the purposes of 

determining compliance with the limits in conditions 38 and 39.

42.f. Recordkeeping Requirement The permittee must maintain the following records 

pertaining to EU1 (combined-cycle combustion turbine) and EU2 and EU3 (simple-cycle

combustion turbines):

42.f.i.A. Hourly average emission rates as follows:

42.f.i.B. parts per million (ppmdv), uncorrected;

42.f.i.C. parts per million (ppmdv), corrected to 15 percent oxygen;

42.f.i.D. pounds per hour (lb/hr);

42.f.i.E. pounds per million Btu (lb/MMBtu); and

42.f.i.F. pounds per megawatt-hour (lb/MWh), if applicable.

42.f.ii. Hourly average O2 emission rates for all combustion turbines;

42.f.iii. Corrected 4-hour rolling NOx emission rates in ppmdv for EU2 and EU3 (simplecycle combustion turbines);

42.f.iv. Corrected 30 unit operating day rolling average NOx emission rates in ppmdv for 

EU1 (combined-cycle combustion turbine);

42.f.v. Records of all operating hours during which data was missing or insufficient data was 

available to calculate a valid hourly average for all combustion turbines;

42.f.vi. For all operating hours during which data was missing or insufficient data was 

available to calculate a valid hourly average, record the reason that insufficient data 

was available.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 22 of 46

43. Reporting Requirement: The permittee must submit reports of NOx emissions that exceed any 

applicable limit in conditions 38 and 39 and monitor downtime with respect to the NOx CEMS for 

emissions units EU1 (combined-cycle combustion turbine) and EU2 and EU3 (simple-cycle combustion 

turbines), in accordance with this condition. [40 CFR 60.4375]

43.a. NOx emissions that exceed any applicable limit in conditions 38 and 39 at any time other 

than during a period that includes hours where startup, shutdown or malfunction occurred

must be reported:

43.a.i. Immediately in accordance with condition 95; and

43.a.ii. Semi-annually in accordance with conditions 43.d and 99.

43.b. NOx emissions that exceed any applicable limit in conditions 38 and 39 during a period of 

startup, shutdown or malfunction must be reported semi-annually in accordance with 

conditions 43.d and 99.

43.c. Monitor downtime must be reported semi-annually in accordance with conditions 43.d and 

99.

43.c.i. A period of monitor downtime is any unit operating hour in which the data for any of 

the following parameters are either missing or invalid: NOX concentration, CO2 or 

O2 concentration, fuel flow rate, steam flow rate, steam temperature, steam pressure, 

or megawatts. The steam flow rate, steam temperature, and steam pressure are only 

required if the permittee will use this information for compliance purposes.

43.d. Report format and content: [40 CFR 60.7(c)]

43.d.i. If the total duration of excess emissions for the reporting period is less than 1 percent 

of the total operating time for the reporting period and CMS downtime for the 

reporting period is less than 5 percent of the total operating time for the reporting 

period, only the summary report form must be submitted and the excess emission 

report need not be submitted unless requested by DEQ.

43.d.ii. If the total duration of excess emissions for the reporting period is 1 percent or greater 

of the total operating time for the reporting period or the total CMS downtime for the 

reporting period is 5 percent or greater of the total operating time for the reporting 

period, the summary report form and the excess emission report must both be 

submitted.

43.d.iii. The excess emission report must include the following information: 

43.d.iii.A. The magnitude of excess emissions computed in accordance with 

§ 60.13(h), any conversion factor(s) used, and the date and time of 

commencement and completion of each time period of excess 

emissions. The process operating time during the reporting period.

43.d.iii.B. Specific identification of each period of excess emissions that 

occurs during startups, shutdowns, and malfunctions of the affected 

facility. The nature and cause of any malfunction (if known), the 

corrective action taken or preventative measures adopted.

43.d.iii.C. The date and time identifying each period during which the 

continuous monitoring system was inoperative except for zero and 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 23 of 46

span checks and the nature of the system repairs or adjustments.

43.d.iii.D. When no excess emissions have occurred or the continuous 

monitoring system(s) have not been inoperative, repaired, or 

adjusted, such information must be stated in the report.

43.d.iv. The summary report form must contain the information and be in the format shown in 

figure 1 in 40 CFR 60.7(d). 

NSPS Subpart KKKK or TTTT, whichever applies

44. Applicable Requirement Upon the dates specified in 40 CFR Part 60 Subpart KKKK or TTTT, 

whichever applies, the permittee must comply with the relevant Subpart KKKK or TTTT CO2 standards 

as applicable to EU1, EU2 and EU3, including all applicable performance testing, recordkeeping and 

reporting requirements. [40 CFR Part 60, Subpart KKKK or TTTT]

Acid Rain Program Requirements

45. Applicable Requirement The permittee must determine and record the heat input (million Btu/hr) to the 

combustion turbines for every hour or part of an hour any fuel is combusted following the procedures in 

appendix F to 40 CFR Part 75. [40 CFR 75.10(c)]

Monitor in accordance with conditions 46 and 47.

46. Monitoring Requirement In accordance with 40 CFR 75.11(d)(2), and Appendix D of part 75, the 

permittee must install, certify, operate, maintain and record the output of fuel flow meters for each type of 

fuel and calculate the SO2 emissions for each hour of operation as follows: 

46.a. While burning ULSD, convert the volumetric flow to mass flow using the density of the oil 

samples and calculate the SO2 emissions using the following equation: 

MSO2 = 2.0 x MULSD x %SULSD/100 

Where:

MSO2 = Hourly mass of SO2 emitted from combustion of ULSD, lb/hr.

Moil = Mass of ULSD consumed per hour, lb/hr.

%Soil = Percentage of sulfur by weight measured in the sample in accordance with 

Condition 37.

2.0 = Ratio of lb SO2/lb S.

46.b. While burning natural gas, employ the hourly metered flow rate of gaseous fuel combusted 

to calculate the SO2 emissions using the following equation: 

MSO2 = (2.0/7000) x GASrate x Sgas

Where:

MSO2 = Hourly mass of SO2 emitted from combustion of natural gas, lb/hr. 

GASrate = Hourly metered flow rate of natural gas fuel combusted, 100 scf/hr. 

Sgas = Sulfur content of natural gas as recorded in accordance with Condition 37.

2.0 = Ratio of lb SO2/lb S.

7000 = conversion of grain/100 scf to lb/100 scf.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 24 of 46

47. Monitoring Requirement In accordance with 40 CFR 75.10(a)(3)(ii), 75.13(b), and appendix G of part 

75, the permittee must install, certify, operate, maintain and record the output of fuel flow meters for each 

type of fuel and calculate the carbon dioxide emissions for each day of operation as follows:

WCO2 = (Fc x H x U1 x MWCO2)/2000

Where:

WCO2 = Daily mass of CO2 emitted from combustion, tons/day

Fc = Carbon based F-factor = 1040 scf/MMBtu for natural gas; a site specific Ffactor shall be derived for ULSD 

H = Daily heat input in MMBtu, as reported in company records

U1 = 1/385 scf CO2/lb-mole at 14.7 psia and 68°F

MWCO2 = Molecular weight of carbon dioxide (44 lb/lb-mole)

47.a. The permittee must ensure that each NOx CEMS and component thereof is capable of 

accurately measuring, recording and reporting data, and must not incur a full scale 

exceedance. [40 CFR 75.10(f)]

47.b. Whenever the permittee makes a replacement, modification or change in the certified NOx 

CEMS,

including the automated DAHS, that significantly affects the ability of the system to measure 

or record the NOx emission rate, the permittee must recertify the NOx CEMS or component 

in accordance with 40 CFR 75.20(b).

47.c. The permittee must operate, calibrate and maintain each NOx CEMS used under the Acid 

Rain Program according to the quality assurance and quality control procedures in appendix 

B of 40 CFR Part 75, including but not limited to the following activities: [40 CFR 75.10(b) 

and 75.21(a)] 

47.c.i. Daily zero and span calibration checks;

47.c.ii. Weekly inspection and maintenance of the CEMS;

47.c.iii. Quarterly linearity checks; and

47.c.iv. Annual relative accuracy test audits.

47.d. The permittee must ensure that all calibration gases used to quality assure the operation of 

the instrumentation required by this permit must meet the definition in 40 CFR 72.2. [40 

CFR 75.21(c)]

47.e. If an out-of-control period occurs to a monitor or NOx CEMS, the permittee must take 

corrective action and repeat the tests applicable to the “out-of-control parameter” in 

accordance with 40 CFR 75.24.

47.f. Whenever a valid hour of NOx emissions rate data has not been measured and recorded, the 

permittee must provide substitute data in accordance with 40 CFR 75.30 through 75.33, 

except the missing data substitution methodology provided for at 40 CFR Part 75, Subpart D, 

is not required for purposes of identifying excess emissions for emission limits in Conditions 

38 and 21. [40 CFR 60.334(b)(3)(iii) and 60.4350(d)]

Source Testing/Performance Testing Requirements

NOx and CO

48. Monitoring Requirement The permittee must perform source tests (performance tests) of emissions 

units EU1, EU2 and EU3 (combustion turbines) for NOx and CO, and RATA testing for the NOx and CO

CEMS in accordance with the following: [40 CFR 60.4405 and 60.8(a)]

48.a. Test schedule:
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 25 of 46

48.a.i. The first test must be performed 60 days after achieving the maximum production rate 

at which the affected facility will be operated on a particular fuel, but not later than 

180 days after initial startup of such facility on that fuel;

48.a.ii. Subsequent tests while burning natural gas must be performed not more than 14 

months after the most recent test. [40 CFR 60.8(a) and 60.4400(a)]

48.b. Tests must be conducted at the following conditions:

48.b.i. EU1 at full load (90 percent of maximum turbine load or more plus maximum duct 

burner firing rate); and 

48.b.ii. EU2 and EU3 at full load (90 percent of maximum turbine load or more).

48.c. The following test methods must be used:

48.c.i. EPA Method 7E must be used for NOx testing; and

48.c.ii. EPA Method 10 must be used for CO testing.

48.d. Source tests and RATAs may be performed simultaneously or separately as provided in 

conditions 48.e, 48.f and 48.g.

48.e. Source tests not combined with RATAs must be performed in accordance with condition 87

general testing.

48.f. RATAs not combined with source tests must be performed in accordance with condition 87, 

except as provided below:

48.f.i. Perform a minimum of nine RATA reference method runs, with a minimum time per 

run of 21 minutes, at more than 50% of normal load.

48.f.ii. For each RATA run, concurrently measure the heat input to the unit using a fuel flow 

meter (or flow meters) and measure the electrical and thermal output from the unit.

48.g. RATAs combined with source tests must be performed in accordance with condition 87, 

except as provided below:

48.g.i. Perform a minimum of nine RATA reference method runs, with a minimum time per 

run of 21 minutes, at a single load level, within plus or minus 10 percent of 100 

percent of peak load. The ambient temperature must be greater than 0 °F during the 

RATA runs.

48.g.ii. For each RATA run, concurrently measure the heat input to the unit using a fuel flow 

meter (or flow meters) and measure the electrical and thermal output from the unit.

48.g.iii. Use the test data both to demonstrate initial compliance with the applicable NOX 

emission limits in conditions 21 22, 23, 38 and 39 and to provide the required 

reference method data for the RATA of the CEMS.

48.g.iv. Compliance with the applicable emission limit in conditions 21, 22, 23, 38 and 39 is 

achieved if the arithmetic average of all of the emission rates for the RATA runs,

expressed in units of ppm, does not exceed the emission limit.

48.h. Recordkeeping and Reporting Requirement The following operational parameters during 

the testing must be monitored, recorded and reported in the final test report:

48.h.i. Turbine load during each test run, in MW and percent of maximum;

48.h.ii. Fuel type and usage rate during each test run.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 26 of 46

Ammonia

49. Monitoring Requirement The permittee must conduct ammonia emissions testing of the exhaust of 

combustion turbines EU1, EU2 and EU3 in accordance with the following: 

49.a. Tests must be performed on the following schedule and at the specified conditions:

49.a.i. The initial test must be conducted within 180 days of startup of each respective 

combustion turbine on natural gas. Testing must be done at conditions A and B.

49.a.i.A. Test condition A is at full load, defined as follows:

Full load for EU1 is 90 percent of maximum turbine load or more, plus 

maximum duct burner firing rate; and

Full load for EU2 and EU3 is 90 percent of maximum turbine load or more.

49.a.i.B. Test condition B is at minimum operating load.

49.a.ii. After the initial test, testing must be conducted annually as specified below, and at the 

conditions specified:

Annual test Schedule Test condition(s)

1

st test 12 months after the preceding test (+/- 1 month). B

2

nd test 12 months after the preceding test (+/- 1 month). B

3

rd test 12 months after the preceding test (+/- 1 month). B

4

th test 12 months after the preceding test (+/- 1 month). B

5

th test Not more than 60 months after the 1st test. A and B

Subsequent 

tests

Subsequent annual tests must be conducted on the same schedule as 

the 1st through 5th tests

49.a.iii. Test condition A is at full load, defined as follows:

Full load for EU1 is 90 percent of maximum turbine load or more, plus maximum 

duct burner firing rate; and

Full load for EU2 and EU3 is 90 percent of maximum turbine load or more.

49.a.iv. Test condition B is at minimum operating load.

49.b. Conditional Test Method CTM-027 must be used unless another method is approved by 

DEQ;

49.c. Source tests must be performed in accordance with condition 87 general testing.

49.d. Recordkeeping and Reporting Requirement The following operational parameters during 

the testing must be monitored, recorded and reported in the final test report:

49.d.i. Turbine load during each test run, in MW and percent of maximum;

49.d.ii. Fuel type and usage rate during each test run;

49.d.iii. Ammonia injection rate during each test run.

VOC

50. Monitoring Requirement The permittee must conduct VOC emissions testing of the exhaust of 

combustion turbines EU1, EU2 and EU3 in accordance with the following: 

50.a. Test schedule:

50.a.i. The first test must be performed 60 days after achieving the maximum production rate 

at which the affected facility will be operated on a particular fuel, but not later than 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 27 of 46

180 days after initial startup of such facility on that fuel. 

50.a.ii. Subsequent tests while burning natural gas must be performed not more than 60 

months after the most recent test.

50.a.iii. Subsequent tests while burning ULSD must be performed as follows:

50.a.iii.A. not more than 60 months after the first test; and

50.a.iii.B. thereafter, not more than 10 years after the most recent test.

50.b. Tests must be conducted at the following conditions:

50.b.i. EU1 at: 

50.b.i.A. full load (90 percent of maximum turbine load or more plus 

maximum duct burner firing rate); and 

50.b.i.B. minimum operating load.

50.b.ii. EU2 and EU3 at:

50.b.ii.A. full load (90 percent of maximum turbine load or more); and 

50.b.ii.B. minimum operating load.

50.c. EPA Method 25A must be used unless another method is approved by DEQ;

50.d. VOC must be reported as methane;

50.e. Source tests must be performed in accordance with condition 87 general testing.

50.f. Recordkeeping and Reporting Requirement The following operational parameters during 

the testing must be monitored, recorded and reported in the final test report:

50.f.i. Turbine load during each test run, in MW and percent of maximum;

50.f.ii. Fuel type and usage rate during each test run.

PM

51. Monitoring Requirement The permittee must conduct PM emissions testing of the exhaust of 

combustion turbines EU1, EU2 and EU3 in accordance with the following: 

51.a. Test schedule:

51.a.i. Natural gas: The first test must be performed 60 days after achieving the maximum 

production rate at which the affected facility will be operated on natural gas, but not 

later than 180 days after initial startup of such facility on that fuel. 

51.a.ii. ULSD: The first test must be performed 60 days after achieving the maximum 

production rate at which the affected facility will be operated on ULSD, but not later 

than 180 days after initial startup of such facility on that fuel. 

51.a.iii. Subsequent tests while burning natural gas must be performed not more than 10 years

after the most recent test.

51.a.iv. Subsequent tests while burning ULSD must be performed as follows:

51.a.iv.A. not more than 60 months after the first test; and

51.a.iv.B. thereafter, not more than 10 years after the most recent test.

51.b. Tests must be conducted at the following conditions:

51.b.i. EU1 at: 

51.b.i.A. While burning ULSD at full load (90 percent of maximum turbine 

load); and 

51.b.i.B. While burning ULSD at minimum operating load.

51.b.ii. EU2 and EU3 at:

51.b.ii.A. While burning ULSD at full load (90 percent of maximum turbine 

load or more); and 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 28 of 46

51.b.ii.B. While burning ULSD at minimum operating load.

51.c. One of the following test methods or pairs of methods must be used: DEQ Method 5; EPA 

Methods 5 and 202, EPA Methods 201a and 202, or Conditional Test Method 039. DEQ 

may also approve an alternative test method.

51.d. Source tests must be performed in accordance with condition 87 general testing.

51.e. Recordkeeping and Reporting Requirement The following operational parameters during 

the testing must be monitored, recorded and reported in the final test report:

51.e.i. Turbine load during each test run, in MW and percent of maximum;

51.e.ii. Fuel type and usage rate during each test run.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 29 of 46

Auxiliary Boiler (EU5) Requirements

Applicable 

Requirement

Condition 

Number

Pollutant/ 

Parameter Limit/Standard

Monitoring 

Condition

Testing 

Condition

340-208-0110 52 Opacity 20% 54 NA

340-228-

0210(1)(b)

53 PM 0.1 gr/dscf 54 NA

40 CFR 60.48c 

and 60.7(a)(3)

55 Notification Notice of startup NA NA

40 CFR 60.11(d) 56 Operation Good air pollution 

control practice

57 NA

BACT (OAR 

340-224-0070)

60 NOx 0.035 lb/MMBtu NA 69

61 CO 0.04 lb/MMBtu NA 69

62 VOC 0.005 lb/MMBtu NA 69

63 PM/PM10/PM2.5 Good combustion 

practices and 

natural gas

59 NA

64 SO2 Good combustion 

practices and 

natural gas

59 NA

65 GHG 117 lb/MMBtu NA 69

Owner requested

limitations

66 Operating mode Limited to natural 

gas fuel

59 NA

67 Operating hours 4,000 hours per 

calendar year

68 NA

Opacity and Particulate Matter Requirements

52. Applicable Requirement The permittee must not cause or allow the emissions of any air contaminant into 

the atmosphere from EU5 for a period or periods aggregating more than three minutes in any one hour 

which is equal to or greater than 20% opacity, excluding uncombined water. [OAR 340-208-0110(2) and 

340-208-0110(3)]. 

Monitor in accordance with condition 54.

53. Applicable Requirement The permittee must not cause or allow the emissions of particulate matter from 

EU5 in excess of 0.1 grains per dry standard cubic foot. [OAR 340-228-0210(1)(b)]. 

Monitor in accordance with condition 54.

54. Monitoring for Conditions 52 and 53 At any time that the permittee is burning natural gas in emission 

unit EU5, the permittee is not required to conduct any visible emissions or particulate matter monitoring 

for that unit because it is extremely unlikely that the standards set forth in Conditions 52 or 53 could be 

violated when the unit is burning natural gas. The permittee must maintain records of the type of fuel 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 30 of 46

being burned in the auxiliary boiler on a monthly basis as required by condition 59.a.ii. If visible 

emissions are to be measured for any reason, the visible emissions must be measured in accordance with 

the Department’s Source Sampling Manual.

NSPS Subpart Dc

Notification of initial startup of the auxiliary boiler, EU5

55. The permittee must submit notification of the actual date of initial startup of the auxiliary boiler, EU5, 

postmarked within 15 days after such date. [40 CFR 60.48c and 60.7(a)(3)].

Additional Subpart Dc Requirements

56. Applicable Requirement At all times, including periods of startup, shutdown, and malfunction, owners 

and operators must, to the extent practicable, maintain and operate any affected facility including 

associated air pollution control equipment in a manner consistent with good air pollution control practice 

for minimizing emissions. [40 CFR 60.11(d)]

Monitor in accordance with condition 57.

57. Monitoring and Recordkeeping Requirement The permittee must keep the following records for the 

auxiliary boiler, EU5:

57.a. Records of the occurrence and duration of any startup, shutdown, or malfunction in the 

operation of the auxiliary boiler, EU5; [40 CFR 60.7(b)]

58. Applicable Requirement The permittee is not subject to SO2 or PM standards in 40 CFR Part 60 Subpart 

Dc provided that only natural gas is combusted in the auxiliary boiler, EU5. [40 CFR 60.42c and 60.43c]

Monitor in accordance with condition 59.

59. Monitoring and Recordkeeping Requirement The permittee must keep the following records for the 

auxiliary boiler, EU5: 

59.a.i. The type of fuel combusted in EU5 during each calendar month; and

59.a.ii. The amount of each fuel combusted in EU5 during each calendar month. [40 CFR 

63.48c(g)(2)]

BACT Requirements

60. Applicable Requirement The permittee must not cause or allow NOx emissions from EU5 in excess of 

0.035 lb/MMBtu on a 3-hour block average, excluding periods of startup and/or shutdown. [BACT limit, 

OAR 340-224-0070(1)].

Test in accordance with condition 69.

61. Applicable Requirement The permittee must not cause or allow CO emissions from EU5 in excess of 0.04 

lb/MMBtu on a 3-hour block average, excluding periods of startup and/or shutdown. [BACT limit, OAR 

340-224-0070(1)].

Test in accordance with condition 69.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 31 of 46

62. Applicable Requirement The permittee must not cause or allow emissions of VOC (reported as methane)

from EU5 in excess 0.005 lb/MMBtu on a 3-hour block average, excluding periods of startup and/or 

shutdown. [BACT limit, OAR 340-224-0070(1)].

Test in accordance with condition 69.

63. Applicable Requirement The permittee must control emissions of PM, PM10 and PM2.5 from EU5 by 

utilizing good combustion practices and the use of natural gas. [BACT limit, OAR 340-224-0070(1)].

Monitor in accordance with condition 59.

64. Applicable Requirement The permittee must control emissions of SO2 from EU5 by utilizing good 

combustion practices and the use of natural gas. [BACT limit, OAR 340-224-0070(1)].

Monitor in accordance with condition 59.

65. Applicable Requirement: The permittee must not cause or allow GHG emissions from EU5 in excess of 

117 lb CO2/MMBtu on a 3-hour block average, excluding periods of startup and/or shutdown. [BACT 

limit, OAR 340-224-0070(1)].

Test in accordance with condition 69.

Owner Requested Limitations

66. Applicable Requirement The auxiliary boiler must combust only natural gas.

Monitor in accordance with condition 59.

67. Applicable Requirement The auxiliary boiler may be operated for no more than 4,000 hours per calendar 

year.

68. Monitoring and Recordkeeping Requirement: The number of hours the auxiliary boiler is operated must

be monitored and recorded each calendar month.

Source Testing/Performance Testing Requirement

69. Monitoring Requirement The permittee must conduct emissions testing of the exhaust of the auxiliary 

boiler EU5 in accordance with the following: 

69.a. The test must be performed not more than 12 months after startup of the facility.

69.b. The test must be for the following pollutants and using the identified methods unless 

otherwise approved by DEQ:

69.b.i. NOx, Method 7E; 

69.b.ii. CO, Method 10;

69.b.iii. VOC, Method 25A and reported as methane; and

69.b.iv. CO2, Method 3A or 3C.

69.c. Source tests must be performed in accordance with condition 87 general testing.

69.d. Recordkeeping and Reporting Requirement The fuel usage rate during each test run, in 

MMcf/hr and MMBtu/hr, must be monitored, recorded and reported in the final test report.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 32 of 46

ULSD Storage Tank (EU6) Requirements

Applicable 

Requirement

Condition 

Number

Pollutant/ 

Parameter Limit/Standard

Testing 

Condition

Monitoring 

Condition

BACT (OAR 

340-224-0070)

70 VOC Submerged fill 

line with vapor 

balancing

NA NA

BACT Requirements

70. Applicable Requirement The permittee must control emissions of VOCs from EU6 as follows:

70.a. The ULSD storage tank, EU6, must be white in color.

70.b. The permittee must install, operate and maintain the tank with a submerged fill pipe. 

70.b.i. The submerged fill pipe must be no more than six (6) inches from the bottom of the 

tank. 

70.b.ii. The permittee must load ULSD into the tank through the submerged fill pipe.

70.c. The permittee must install, operate and maintain the tank with a vapor balance control 

system to transfer vapor emissions from the tank to the ULSD fuel truck during tank loading 

operations. The permittee must use the vapor balance control system as necessary when 

ULSD is loaded into the tank to minimize venting of vapor emissions from within the tank to 

the atmosphere. 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 33 of 46

Insignificant Activities Requirements, Including Cooling Towers (EU4) and Fire Pump Engine (EU7)

71. DEQ acknowledges that insignificant emissions units (IEUs) identified by rule as either categorically 

insignificant activities or aggregate insignificant emissions as defined in OAR 340-200-0020 exist at 

facilities required to obtain an Oregon Title V Operating Permit. IEUs must comply with all applicable 

requirements. In general, the requirements that could apply to IEUs are incorporated as follows:

71.a. OAR 340-208-0110 (20% opacity)

71.b. OAR 340-228-0210 (0.1 gr/dscf corrected to 12% CO2 or 50% excess air for fuel burning 

equipment)

71.c. OAR 340-226-0210 (0.1 gr/dscf for non-fugitive, non-fuel burning equipment)

71.d. OAR 340-226-0310 (process weight limit for non-fugitive, non-fuel burning process 

equipment)

71.e. OAR 340-226-0120 (no chromium-based water treatment chemicals in the cooling towers)

Unless otherwise specified in this permit or an applicable requirement, DEQ is not requiring any testing, 

monitoring, recordkeeping, or reporting for the applicable emissions limits and standards that apply to 

IEUs. However, if testing were performed for compliance purposes, the permittee would be required to use 

the test methods identified in the definitions of “opacity” and “particulate matter” in OAR 340-208-0010 

and perform the testing in accordance with DEQ’s Source Sampling Manual.

Cooling Towers, EU4

72. Emission unit EU4 (cooling towers) is considered to be part of the IEU, and is subject to all applicable 

requirements.

Fire Pump Engine, EU7

Applicable 

Requirement

Condition 

Number

Pollutant/ 

Parameter Limit/Standard

Testing 

Condition

Monitoring 

Condition

340-208-0110 71 Visible 

emissions

20% opacity NA 71

340-226-0210(2) 71 PM 0.1 gr/dscf NA 71

340-228-0210(2) 71 PM 0.1 gr/dscf @12%

CO2

NA 71

BACT 73 NOx, CO, VOC, 

H2SO4, PM10 

and PM2.5 and 

GHG

See condition 73 NA NA

40 CFR Part 63

Subpart ZZZZ

74 n/a Comply with 40 

CFR Part 60

Subpart IIII 

NA NA

40 CFR 63.11(d) 75 O&M See condition 75 NA 76

40 CFR 

60.4205(c)

77 NMHC+NOx, 

PM

3.0 g/HP-hr,

0.15 g/HP-hr

NA 77.c

40 CFR 

60.4207(b)

79 Fuel sulfur 

content

15 ppm max NA 80
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 34 of 46

Applicable 

Requirement

Condition 

Number

Pollutant/ 

Parameter Limit/Standard

Testing 

Condition

Monitoring 

Condition

40 CFR 

60.4211(a)

81 Operating 

requirements

See condition 81 NA NA

40 CFR 

60.4211(f)

82 Non-emergency 

time limit

100 hours per 

calendar year

NA 83

73. Applicable Requirement The permittee must comply with the requirements below for the emergency 

fire pump engine, EU7: [NSR/PSD permit 26-0235 BACT]

Pollutant Requirements

NOx Utilize a pump engine that meets the RICE NSPS requirements.

Utilize lean burn combustion, good combustion practices, turbocharging and 

aftercooling.

CO Utilize good combustion practices.

VOC Utilize good combustion practices.

H2SO4 Utilize ULSD fuel and good combustion practices.

PM10 and PM2.5 Utilize ULSD fuel and good combustion practices.

GHG Utilize energy efficient engine, and do not cause or allow emissions of CO2 to exceed 

163 lb CO2/MMBtu.

No testing is required because EU7 is a categorically insignificant emissions unit.

74. Applicable Requirement Emission unit EU7 is an insignificant emission unit (IEU), as per Condition 

71, subject to all applicable requirements. It is subject to NSPS, Subpart IIII, Standards of Performance 

for Stationary Ignition Internal Combustion Engines. [40 CFR 60.4200 – 60.4219]. The applicability of 

the NSPS Subpart IIII requirements to this engine also satisfies the requirements of the 40 CFR Part 63, 

Subpart ZZZZZ NESHAP. The permittee must comply with 40 CFR Part 63 Subpart ZZZZ by complying 

with conditions 75 through 83, which implement the requirements of 40 CFR Part 60 Subpart IIII. [40 

CFR 63.6590(c)]

75. Applicable Requirement At all times, including periods of startup, shutdown, and malfunction, owners 

and operators must, to the extent practicable, maintain and operate any affected facility including 

associated air pollution control equipment in a manner consistent with good air pollution control practice 

for minimizing emissions. [40 CFR 60.11(d)]

Monitor in accordance with condition 76.

76. Monitoring and Recordkeeping Requirement The permittee must keep the following records for the fire 

pump engine, EU7:

76.a. Records of the occurrence and duration of any startup, shutdown, or malfunction in the 

operation of an affected facility; [40 CFR 60.7(b)]

76.b. Records of any major maintenance; and

76.c. Records of any repairs or corrective actions taken as a result of malfunctions or upsets.

Monitor in accordance with condition 76.

77. Applicable Requirement The permittee must comply with the following emission standards for 

stationary fire pump engines [40 CFR 60.4205(c) and Table 4 to Subpart IIII of Part 60]
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 35 of 46

77.a. NMHC + NOx: 4.0 g/Kw-hr or 3.0 g/HP-hr

77.b. PM: 0.2 g/Kw-hr or 0.15 g/HP-hr

77.c. The permittee must demonstrate compliance with the emission standards in this condition 

by: [40 CFR 63.4211(c)]

77.c.i. Purchasing an engine certified to the emission standards in this condition; and

77.c.ii. The engine must be installed and configured according to the manufacturer’s 

emission-related specifications.

78. Monitoring and Recordkeeping Requirement The permittee must keep the following records:

78.a.i. Engine make, model and power rating;

78.a.ii. The engine manufacturer’s certification that the engine meets the emissions standards 

in conditions 77.a and 77.b; and

78.a.iii. Records of the engine manufacturer’s emission-related specifications regarding 

installation and configuration. 

79. Applicable Requirement The permittee must use fuel with a sulfur content of 15 ppm maximum. [40 

CFR 60.4207(b) and 40 CFR 80.510(b)]

Monitor in accordance with condition 80.

80. Monitoring Requirement: The permittee must monitor compliance with condition 79 by performing the 

monitoring required by condition 37. 

81. Applicable Requirement The permittee must comply with the following: [40 CFR 60.4211(a)]

81.a. Operate and maintain the stationary CI internal combustion engine according to the 

manufacturer’s emission-related written instructions;

81.b. Change only those emission-related settings that are permitted by the manufacturer; and

81.c. Meet the requirements of 40 CFR parts 89, 94 and/or 1068, as they apply to you.

82. Applicable Requirement The permittee must operate the emergency stationary ICE according to the 

requirements in conditions 82.a and 82.b. In order for the engine to be considered an emergency stationary 

ICE under this subpart, any operation other than emergency operation, maintenance and testing, 

emergency demand response, and operation in non-emergency situations for 50 hours per year, as 

described in conditions 82.b.i and 82.b.ii is prohibited. If the permittee does not operate the engine 

according to the requirements in conditions 82.a and 82.b, the engine will not be considered an emergency 

engine under subpart IIII and must meet all requirements for non-emergency engines. [40 CFR 

60.4211(f)]

82.a. There is no time limit on the use of emergency stationary ICE in emergency situations.

82.b. You may operate your emergency stationary ICE for any combination of the purposes 

specified in conditions 82.b.i and 82.b.ii for a maximum of 100 hours per calendar year. Any 

operation for non-emergency situations as allowed by condition 82.b.ii counts as part of the 

100 hours per calendar year allowed by this condition.

82.b.i. Emergency stationary ICE may be operated for maintenance checks and readiness 

testing, provided that the tests are recommended by federal, state or local government, 

the manufacturer, the vendor, the regional transmission organization or equivalent 

balancing authority and transmission operator, or the insurance company associated 

with the engine. The owner or operator may petition the Administrator for approval of 

additional hours to be used for maintenance checks and readiness testing, but a 

petition is not required if the owner or operator maintains records indicating that 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 36 of 46

federal, state, or local standards require maintenance and testing of emergency ICE 

beyond 100 hours per calendar year.

82.b.ii. Emergency stationary ICE may be operated for up to 50 hours per calendar year in 

non-emergency situations. The 50 hours of operation in non-emergency situations are 

counted as part of the 100 hours per calendar year for maintenance and testing and 

emergency demand response provided in condition 82.b. Limitations on the use of 

emergency stationary ICE in non-emergency situations are stated in 40 CFR 

60.4211(f)(3).

Monitor in accordance with condition 83.

83. Monitoring and Recordkeeping Requirement The permittee must monitor operating time of the engine 

and the reason for operation each time it is used for emergency or non-emergency use. [40 CFR 

60.4214(b)]

83.a. Recordkeeping The permittee must keep the following records each time the engine is 

operated:

83.a.i. Date;

83.a.ii. Time of operation based on the beginning and ending hour meter readings; and

83.a.iii. The reason the engine was in operation during that time. 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 37 of 46

PLANT SITE EMISSION LIMITS

84. The plant site emissions must not exceed the following limits for any 12 consecutive calendar month 

period: [OAR 340-222-0040 through OAR 340-222-0043]

Pollutant

Plant Site Emission Limit 

(tons/yr)

Unassigned Emissions 

(tons/yr)

Emission Reduction 

Credit (tons/yr)

PM 198 0 0

PM10 198 0 0

PM2.5 198 0 0

SO2 39 0 0

NOx 227 0 0

CO 643 0 0

VOC 212 0 0

H2SO4 19 0 0

GHG (CO2e) 2,730,000* 0 0

* Rounded to the nearest 1,000

85. The netting basis will be reduced in accordance with the following: [OAR 340-200-0020(76)(g), 

definition of Netting Basis]

85.a. Notwithstanding OAR 340-222-0041(2), this adjustment does not require a reduction in the 

PSEL. [OAR 340-200-0020(76)(g), definition of Netting Basis]

85.b. Actual emissions on the date this permit is first issued equal the potential to emit of the 

source. The actual emissions will be reset in accordance with paragraph 85.c. [OAR 340-

200-0020(3)(b), definition of Actual Emissions]

85.c. The potential emissions will be reset to actual emissions as follows: [OAR 340-200-

0020(3)(c), definition of Actual Emissions]

85.c.i. Except as provided in paragraph 85.c.iii, ten years from the date this permit was 

initially issued, or an earlier time if requested by the source in a permit application 

involving public notice, DEQ will reset actual emissions to equal the highest actual 

emission rate during any consecutive 12-month period during the ten year period or 

any shorter period if requested by the source. 

85.c.ii. Any emission reductions achieved due to enforceable permit conditions based on 

OAR 340-226-0110 and 0120 (highest and best practicable treatment and control) are 

not included in the reset calculation. 

85.c.iii. DEQ may extend the date of resetting by five additional years upon satisfactory 

demonstration by the source that construction is ongoing or normal operation has not 

yet been achieved. 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 38 of 46

Plant Site Emissions Limit Monitoring [<reserved, future Title V condition or reference>]

86. The permittee must determine compliance with the Plant Site Emission Limits established in Condition 84 of 

this permit by conducting monitoring and calculations for each 12-month period in accordance with the 

following procedures, test methods, and frequencies:

86.a. The permittee must calculate emissions using the following formula, process parameters, and 

emission factors, except as required in conditions 86.b, 86.c, 86.d and 86.e:

E = Peu x EFeu x K

Where:

E = Pollutant emissions in lbs/month and tons/yr.

Peu = Process parameter identified in the table below;

EFeu = Emission factor identified for each emissions unit and pollutant in the table 

below;

K = Conversion constant: 1 lb/lb for daily and monthly emissions calculations; 1 

ton/2,000 lbs for annual emissions calculations.

Emission Factor Table

Emission 

Source

and

Fuel

Throughput Units

Emission Factors - lb/[throughput unit]

Operating 

Mode

PM10/

PM2.5 SO2 NOX CO VOC H2SO4

EU1

combined 

cycle 

combustion 

turbine

Natural gas

normal, 

with duct 

firing [MMBtu] 0.0085

Acid Rain 

Calculations

(condition 

47)

CEM

(condition 

41)

CEM

(condition 

42)

0.00257 0.00048

normal, 

without 

duct firing [MMBtu] 0.0068

cold start [event] 56.9 16.7 475.5 6000 3524.0

warm start [event] 13.0 6.2 82.9 3939.4 898.1

hot start [event] 5.5 3.2 62.0 1757.88 386.9

shutdown [event] 1.8 1.9 9.2 263.5 66.8

EU1 

combined 

cycle 

combustion 

turbine

ULSD

normal [MMBtu] 0.0165

Acid Rain 

Calculations CEM CEM 0.00678 0.00051

cold start [event] 293.8 22.5 1072.4 7710 6461.1

warm start [event] 54.4 8.4 169.6 6313.9 1313.3

hot start [event] 30.0 4.3 145.0 3732.72 475.32

shutdown [event] 5.6 2.5 20.8 735.8 122.5
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 39 of 46

Emission Factor Table, continued

Emission 

Source

and

Fuel

Throughput Units

Emission Factors - lb/[throughput unit]

Operating 

Mode

PM10/

PM2.5 SO2 NOX CO VOC H2SO4

EU2 & EU3 

simple cycle 

combustion 

turbines

Natural gas

normal [MMBtu] 0.011

Acid Rain 

Calculations CEM CEM 0.0045 0.0015

startup [event] 0.22 0.11 3.01 10.21 0.16

shutdown

[event]

0.24 0.13 3.97 13.21 0.21

EU2 & EU3 

simple cycle 

combustion 

turbines

ULSD

normal [MMBtu] 0.028

Acid Rain 

Calculations CEM CEM 0.00678 0.0016

startup [event] 0.40 0.05 6.67 10.22 0.32

shutdown

[event]

0.44 0.06 8.77 10.38 0.36

EU5 

auxilliary 

boiler Natural gas [MMBtu] 0.0050 0.0015 0.035 0.040 0.0050 negligible

EU6 ULSD 

storage tank

Constant

[Year] 780

aggregate 

insignificant 

emissions Constant

Constant

[Year] 2000 2000 2000 2000 2000 1400

NOx

86.b. The permittee must calculate the rolling 12-month NOx emissions by summing the 

following:

86.b.i. All of the hourly mass emissions during the 12-calendar month period from each 

turbine measured in accordance with Condition 40; and

86.b.ii. The monthly emissions during the 12-calendar month period from the auxiliary boiler 

as determined in accordance with Condition 86.a.

CO

86.c. The permittee must calculate the rolling 12-month CO emissions by summing the following:

86.c.i. All of the hourly mass emissions during the 12-calendar month period from each 

turbine measured in accordance with Condition 41; and

86.c.ii. The monthly emissions during the 12-calendar month period from the auxiliary boiler 

as determined in accordance with Condition 86.a.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 40 of 46

GHG

Fuel Throughput Units

Emission Factors (lb/throughput unit)

CO2 CH4 N2O

Natural Gas million Btu 116.89 0.0022 0.00022

ULSD million Btu 163.05 0.0066 0.0013

Monthly GHG emissions

86.d. The permittee must calculate the monthly GHG emissions by adding the following:

86.d.i. The sum of all of the CO2 hourly mass emissions during the calendar month period

from each turbine measured in accordance with Condition 47; 

86.d.ii. The monthly CH4 and N2O emissions from each turbine, as determined in accordance 

with the formula in Condition 86.a and the emission factors above; and

86.d.iii. The monthly CO2, CH4 and N2O emissions from the auxiliary boiler, as determined in 

accordance with the formula in Condition 86.a and the emission factors above.

Rolling 12-month GHG emissions

86.e. The permittee must calculate the rolling 12-month GHG emissions as follows:

86.e.i. Sum the monthly CO2, CH4 and N2O emissions, as determined in accordance with 

condition 86.d, for the 12-calendar month period; 

86.e.ii. Convert the mass emissions of CO2, CH4 and N2O to CO2e using the global 

warming potentials (GWP) below; and

GHG gas GWP

CO2 1

CH4 21

N2O 310

86.e.iii. Add the CO2e results together to determine compliance with the PSEL for GHG.

86.f. The emissions factors listed in Condition 86.a are not enforceable limits unless otherwise 

specified in this permit. Compliance with PSELs must only be determined by the 

calculations contained in this Condition.

86.g. Compliance with PSELs must be determined using the calculations contained in condition 86

using the monitored parameters recorded during the reporting period and the emission 

factors contained in condition 86, unless the permittee elects to pay emission fees based on 

actual emissions using a verified emission factor determined in accordance with OAR 340-

220-0170. If the permittee is paying on actual emissions based on a verified emission factor, 

the verified emission factor must be used for determining compliance with the PSEL in 

accordance with condition 86.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 41 of 46

GENERAL TESTING REQUIREMENTS

87. Unless otherwise specified in this permit, the permittee must conduct all testing in accordance with DEQ’s 

Source Sampling Manual. [OAR 340-212-0120; 40 CFR 60.8] 

87.a. Unless otherwise specified by a state or federal regulation, the permittee must submit a 

source test plan to DEQ at least 30 days prior to the date of the test. The test plan must be 

prepared in accordance with the Source Sampling Manual and address any planned 

variations or alternatives to prescribed test methods. Permittee should be aware, if significant 

variations are requested, it may require more than 30 days for DEQ to grant approval and 

may require EPA approval in addition to approval by DEQ.

87.b. Only regular operating staff may adjust the processes or emission control device parameters 

during a compliance source test and within two (2) hours prior to the tests. Any operating 

adjustments made during a compliance source test, which are a result of consultation during 

the tests with source testing personnel, equipment vendors, or consultants, may render the 

source test invalid.

87.c. Unless otherwise specified by permit condition or Department approved source test plan, all 

compliance source tests must be performed as follows:

87.c.i. at least 90% of the design capacity for new or modified equipment;

87.c.ii. at least 90% of the maximum operating rate for existing equipment; or

87.c.iii. at 90 to 110% of the normal maximum operating rate for existing equipment. For 

purposes of this permit, the normal maximum operating rate is defined as the 90th 

percentile of the average hourly operating rates during a 12 month period immediately 

preceding the source test. Data supporting the normal maximum operating rate must 

be included with the source test report.

87.d. Each source test must consist of at least three (3) test runs and the emissions results must be 

reported as the arithmetic average of all valid test runs. If for reasons beyond the control of 

the permittee a test run is invalid, DEQ may accept two (2) test runs for demonstrating 

compliance with the emission limit or standard.

87.e. Source test reports prepared in accordance with DEQ’s Source Sampling Manual must be 

submitted to DEQ within 45 days of completing any required source test, unless a different 

time period is approved in the source test plan submitted prior to the source test.

GENERAL MONITORING AND RECORDKEEPING REQUIREMENTS

General Monitoring Requirements:

88. <reserved, future Title V condition or reference>

89. <reserved, future Title V condition or reference>

90. <reserved, future Title V condition or reference>
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 42 of 46

General Recordkeeping Requirements

91. <reserved, future Title V condition or reference>

92. <reserved, future Title V condition or reference>

93. <reserved, future Title V condition or reference>

94. Unless otherwise specified, all records must be maintained on site for a period of two (2) years and made 

available to DEQ upon request.

REPORTING REQUIREMENTS

95. Excess Emissions Reporting The permittee must report all excess emissions as follows: [OAR 340-214-

0300 through 340-214-0360]

95.a. No later than 9:00 am the next DEQ working day, notify DEQ of an excess emission event 

by phone, email, or facsimile; and 

95.b. Within 15 days of the excess emissions event, submit a written report that contains the 

following information: [OAR 340-214-0340(1)]

95.b.i. The date and time of the beginning of the excess emissions event and the duration or 

best estimate of the time until return to normal operation;

95.b.ii. The date and time the owner or operator notified DEQ of the event;

95.b.iii. The equipment involved;

95.b.iv. Whether the event occurred during planned startup, planned shutdown, scheduled 

maintenance, or as a result of a breakdown, malfunction, or emergency;

95.b.v. Steps taken to mitigate emissions and corrective action taken, including whether the 

approved procedures for a planned startup, shutdown, or maintenance activity were 

followed;

95.b.vi. The magnitude and duration of each occurrence of excess emissions during the course 

of an event and the increase over normal rates or concentrations as determined by 

continuous monitoring or best estimate (supported by operating data and 

calculations);

95.b.vii. The final resolution of the cause of the excess emissions; and

95.b.viii. Where applicable, evidence supporting any claim that emissions in excess of 

technology-based limits were due to any emergency pursuant to OAR 340-214-0360.

95.c. In the event of any excess emissions which are of a nature that could endanger public health 

and occur during non-business hours, weekends, or holidays, the permittee must immediately 

notify DEQ by calling the Oregon Accident Response System (OARs). The current number 

is 1-800-452-0311.

95.d. If startups, shutdowns, or scheduled maintenance may result in excess emissions, the 

permittee must submit startup, shutdown, or scheduled maintenance procedures used to 

minimize excess emissions to DEQ for prior authorization, as required in OAR 340-214-

0310 and 340-214-0320. New or modified procedures must be received by DEQ in writing at 

least 72 hours prior to the first occurrence of the excess emission event. The permittee must 

abide by the approved procedures and have a copy available at all times. 

95.e. The permittee must notify DEQ of planned startup/shutdown or scheduled maintenance 

events.

95.f. The permittee must continue to maintain a log of all excess emissions in accordance with 

OAR 340-214-0340(3). However, the permittee is not required to submit the detailed log 
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 43 of 46

with the semi-annual and annual monitoring reports. The permittee is only required to submit 

a brief summary listing the date, time, and the affected emissions units for each excess 

emission that occurred during the reporting period. [<reserved, future Title V condition or 

reference>]

96. Permit Deviations Reporting: The permittee must promptly report deviations from permit requirements 

that do not cause excess emissions, including those attributable to upset conditions, as defined in the 

permit, the probable cause of such deviations, and any corrective actions or preventive measures taken. 

“Prompt” means within 15 days of the deviation. Deviations that cause excess emissions, as specified in 

OAR 340-214-0300 through 340-214-0360 must be reported in accordance with Condition 95.

97. <reserved, future Title V condition or reference>

98. <reserved, future Title V condition or reference>

Addresses of regulatory agencies are the following, unless otherwise instructed:

DEQ – Northwest Region

2020 SW Fourth Avenue, Suite 400

Portland, OR 97201

503-229-5263

DEQ – Air Quality Division

811 SW Sixth Avenue

Portland, OR 97204

503-229-5359

Semi-annual and Annual Reports

99. For each year this permit is in effect, the permittee must submit to DEQ by February 15 two (2) copies of 

the following information for the previous calendar year:

99.a. The semi-annual report is due on July 30 and must consist of the following:

99.a.i. the semi-annual excess emissions report required by condition 43.

99.a.ii. the semi-annual CEMS monitor downtime report required by conditions 43

99.b. The annual report is due on February 15 and must consist of the following:

99.b.i. the monthly rolling 12-month emissions for each month for the report year;

99.b.ii. the number and type (cold, warm, hot) of startups and shutdowns each month for the 

report year for emissions units EU1, EU2 and EU3 (combustion turbines);

99.b.iii. the monthly rolling 12-month total startup time and monthly rolling 12-month 

shutdown time for emissions units EU1, EU2 and EU3 (combustion turbines);

99.b.iv. the NOx and VOC emission statement, if applicable; [OAR 340-214-0220]; 

99.b.v. a summary of the excess emissions upset log (condition 95.f); [OAR 340-214-0340]

99.b.vi. the annual certification that the risk management plan is being properly implemented, 

if required; OAR 340-244-0230. [<reserved, future Title V condition or reference>]

99.b.vii. the semi-annual excess emissions report required by condition 43.

99.b.viii. the semi-annual CEMS monitor downtime report required by conditions 43.

100. <reserved, future Title V condition or reference>

101. Greenhouse Gas Registration and Reporting: If the calendar year emission rate of greenhouse gases 

(CO2e) is greater than or equal to 2,756 tons (2,500 metric tons), the permittee must register and report its 

greenhouse gas emissions with DEQ in accordance with OAR 340-215.

102. <reserved, future Title V condition or reference>
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 44 of 46

STANDARD ACDP REQUIREMENTS AND GENERAL CONDITIONS

103. REPORTING REQUIREMENTS

103.a. Initial Startup Notice The permittee must notify DEQ in writing of the date a new facility is started 

up. The notification must be submitted no later than seven (7) days after 

startup.

103.b. Notice of Change of 

Ownership or Company 

Name

The permittee must notify DEQ in writing using a Departmental “Permit 

Application Form” within 60 days after the following:

103.b.i. Legal change of the name of the company as registered with the 

Corporations Division of the State of Oregon; or

103.b.ii. Sale or exchange of the activity or facility.

103.c. Construction or 

Modification Notices

The permittee must notify DEQ in writing using a Departmental “Notice of 

Construction Form,” or “Permit Application Form,” and obtain approval in 

accordance with OAR 340-210-0205 through 340-210-0250 before:

103.c.i. Constructing, installing, or establishing a new stationary source that 

will cause an increase in any regulated pollutant emissions;

103.c.ii. Making any physical change or change in operation of an existing 

stationary source that will cause an increase, on an hourly basis at full 

production, in any regulated pollutant emissions; or

103.c.iii.Constructing or modifying any air pollution control equipment.

103.d. Where to Send Reports 

and Notices

The reports, with the permit number prominently displayed, must be sent to the 

Permit Coordinator for DEQ’s Northwest Region Office.

104. ADMINISTRATIVE REQUIREMENTS

104.a. Permit Modifications Application for a modification of this permit must be submitted not less than 60

days prior to the source modification. A special activity fee must be submitted 

with an application for the permit modification. The fees and two (2) copies of 

the application must be submitted to the DEQ Business Office.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 45 of 46

105. FEES

105.a. Annual Compliance Fee The Annual Fee specified in OAR 340-216-0020, Table 2, Part 2 for a Standard 

ACDP is due on December 1 of each year this permit is in effect. An invoice 

indicating the amount, as determined DEQ regulations will be mailed prior to 

the above date. Late fees in accordance with Part 4 of the table will be 

assessed as appropriate.

105.b. Change of Ownership 

or Company Name Fee

The non-technical permit modification fee specified in OAR 340-216-0020, 

Table 2, Part 3(a) is due with an application for changing the ownership or the 

name of the company.

105.c. Special Activity Fees The special activity fees specified in OAR 340-216-0020, Table 2, Part 3 (b 

through i) are due with an application to modify the permit.

105.d. Where to Submit Fees Fees must be submitted to:

Department of Environmental Quality

Business Office

811 SW Sixth Avenue

Portland, Oregon 97204-1390

106. GENERAL CONDITIONS AND DISCLAIMERS

106.a. Permitted Activities This permit allows the permittee to discharge air contaminants from processes 

and activities related to the air contaminant source(s) listed on the first page of 

this permit until this permit expires, is modified, or is revoked.

106.b. Other Regulations In addition to the specific requirements listed in this permit, the permittee must 

comply with all other legal requirements enforceable by DEQ.

106.c. Conflicting Conditions In any instance in which there is an apparent conflict relative to conditions in 

this permit, the most stringent conditions apply.

106.d. Masking of Emissions The permittee must not cause or permit the installation of any device or use any 

means designed to mask the emissions of an air contaminant that causes or is 

likely to cause detriment to health, safety, or welfare of any person or otherwise 

violate any other regulation or requirement.

106.e. Department Access The permittee must allow DEQ’s representatives access to the plant site and 

pertinent records at all reasonable times for the purposes of performing 

inspections, surveys, collecting samples, obtaining data, reviewing and copying 

air contaminant emissions discharge records and conducting all necessary 

functions related to this permit in accordance with ORS 468-095.

106.f. Permit Availability The permittee must have a copy of the permit available at the facility at all 

times.

106.g. Open Burning The permittee may not conduct any open burning except as allowed by OAR 

340 Division 264.

106.h. Asbestos The permittee must comply with the asbestos abatement requirements in OAR 

340, Division 248 for all activities involving asbestos-containing materials, 

including, but not limit to, demolition, renovation, repair, construction, and 

maintenance.
Permit number: 26-0235-ST-01

Final Expiration date: 04/01/2019

Page 46 of 46

106.i. Property Rights The issuance of this permit does not convey any property rights in either real or 

personal property, or any exclusive privileges, nor does it authorize any injury 

to private property or any invasion of personal rights, nor any infringement of 

federal, state, or local laws or regulations.

106.j. Permit Expiration 106.j.i. A source may not be operated after the expiration date of the permit, 

unless any of the following occur prior to the expiration date of the 

permit:

106.j.i.A. a timely and complete application for renewal or for 

an Oregon Title V Operating Permit has been submitted, or

106.j.i.B. another type of permit (ACDP or Oregon Title V 

Operating Permit) has been issued authorizing operation of 

the source.

106.j.ii. For a source operating under an ACDP or Oregon Title V Operating 

Permit, a requirement established in an earlier ACDP remains in effect 

notwithstanding expiration of the ACDP, unless the provision expires 

by its terms or unless the provision is modified or terminated 

according to the procedures used to establish the requirement initially.

106.k. Permit Termination, 

Revocation, or 

Modification

DEQ may modify or revoke this permit pursuant to OAR 340-216-0082 and 

340-216-0084.

ALL INQUIRIES SHOULD BE DIRECTED TO:

Northwest Region

2020 SW 4th Avenue, Suite 400

Portland, OR 97201

503-229-5263
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 1 of 31

OREGON DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR CONTAMINANT DISCHARGE PERMIT 

REVIEW REPORT FOR

Troutdale Energy Center, LLC

Northwest Region

2020 SW 4th Ave., Suite 400

Portland, OR 97201

Source Information:

SIC 4911

NAICS 221112

Source Categories (Part and code) B.27

Compliance and Emissions Monitoring Requirements:

Unassigned emissions no

Emission credits no

Compliance schedule no

Source test [date(s)] vary

COMS no

CEMS yes

PEMS no

Ambient monitoring no

Reporting Requirements

Annual report (due date) February 15

Emission fee report (due date) NA

SACC (due date) NA

Quarterly report (due dates) NA

Monthly report (due dates) n/a

Excess emissions report yes

Other reports (type) n/a

Air Programs

NSPS (list subparts) Dc, IIII, KKKK, 

TTTT

NESHAP (list subparts) ZZZZ

CAM n/a

Regional Haze (RH) no

Synthetic Minor (SM) no

Part 68 Risk Management no

CFC no

RACT no

TACT no

Title V yes

ACDP (SIP) yes

Major HAP source no

Federal major source yes

NSR yes

PSD yes

Acid Rain yes
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 2 of 31

TABLE OF CONTENTS

PERMITTEE IDENTIFICATION ................................................................................................................................4

FACILITY DESCRIPTION ..........................................................................................................................................4

NEW SOURCE REVIEW (NSR) AND PREVENTION OF SIGNIFICANT DETERIORATION (PSD) ..................9

BACT DETERMINATION.........................................................................................................................................12

FINAL BACT DETERMINATIONS AND AMMONIA LIMIT ...............................................................................18

AIR QUALITY ANALYSIS.......................................................................................................................................23

EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECORDKEEPING.......................24

PLANT SITE EMISSION LIMITS.............................................................................................................................29

HAZARDOUS AIR POLLUTANTS ..........................................................................................................................31

COMPLIANCE HISTORY.........................................................................................................................................31

SOURCE TEST RESULTS.........................................................................................................................................31

PUBLIC NOTICE .......................................................................................................................................................31
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 3 of 31

LIST OF ABBREVIATIONS USED IN THIS REVIEW REPORT

AQMA Air Quality Management Area

ASTM American Society of Testing and 

Materials

BDT bone dry ton

CEMS continuous emissions monitoring 

system

CFR Code of Federal Regulations

CH4 methane (greenhouse gas)

CI compression ignition

CMS continuous monitoring system

CO carbon monoxide

CO2e carbon dioxide equivalent

COMS continuous opacity monitoring 

system

DEQ Oregon Department of 

Environmental Quality

dscf dry standard cubic feet

EF emission factor

EPA United State Environmental 

Protection Agency

EU emissions unit

FCAA Federal Clean Air Act

FGR flue gas recirculation

GHG greenhouse gas

gr/dscf grains per dry standard cubic feet

HAP hazardous air pollutant

ID identification code

I&M inspection and maintenance

MB material balance

Mlb 1000 pounds

MM million

N2O nitrous oxide (greenhouse gas)

NA not applicable

NESHAP National Emission Standard for 

Hazardous Air Pollutants

NOx oxides of nitrogen

NSPS New Source Performance Standard

NSR New Source Review

O2 oxygen

OAR Oregon Administrative Rules

ORS Oregon Revised Statutes

O&M operation and maintenance

Pb lead

PCD pollution control device

PEMS predictive emissions monitoring 

system

PM particulate matter

PM10 particulate matter less than 10 

microns in size

PM2.5 particulate matter less than 2.5 

microns in size

ppm parts per million

ppmdv parts per million, dry, by volume

PSD Prevention of Significant 

Deterioration

PSEL Plant Site Emission Limit

RICE reciprocating internal combustion 

engine

SO2 sulfur dioxide

ST source test

ULSD ultra-low sulfur distillate

VE visible emissions

VMT vehicle mile traveled

VOC volatile organic compound
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 4 of 31

INTRODUCTION

1. On November 6, 2012, DEQ received an application for a new Standard Air Contaminant Discharge Permit 

(ACDP) for the proposed Troutdale Energy Center. The applicant submitted an addendum to its application 

that DEQ received on April 5, 2013.

1.a. This facility is classified as a federal major source and is subject to the following regulatory 

programs:

1.a.i. Prevention of Significant Deterioration (PSD) for attainment/unclassified areas; and

1.a.ii. New Source Review (NSR) for maintenance areas.

1.b. A Standard ACDP must be issued before the facility may be built; the ACDP will also allow the 

facility to operate after construction is completed.

1.c. This facility is also subject to Title V permitting requirements and must apply for a Title V permit to 

replace the ACDP within one year of commencing operation.

2. In accordance with OAR 340-218-0120(1)(f), this review report is intended to provide the legal and factual 

basis for the draft permit conditions. In most cases, the legal basis for a permit condition is included in the 

permit by citing the applicable regulation. In addition, the factual basis for the requirement may be the same as 

the legal basis. However, when the regulation is not specific and only provides general requirements, this 

review report is used to provide a more thorough explanation of the factual basis for the draft permit 

conditions.

PERMITTEE IDENTIFICATION

3. Troutdale Energy Center (TEC) proposes to construct and operate a 653 megawatt (MW) electric generating 

plant in Troutdale, Oregon. TEC proposes to generate electricity with three natural gas-fired turbines, one of 

which will be a combined-cycle unit with duct burner and heat recovery steam generator. Ultra-low sulfur 

distillate (ULSD) fuel (also known as ultra-low sulfur diesel and may include biofuels) will be the backup fuel.

TEC will be located at Troutdale Reynolds Industrial Park, lot 3, on the former Reynolds Aluminum site.

Historically, the site was home to an aluminum plant owned and operated by Reynolds Metals Company and, 

later, Alcoa, Inc. The aluminum plant closed in 2002. Its operations caused contamination at the site, which 

has since been cleaned up to the U.S. Environmental Protection Agency’s standards for industrial use. TEC’s 

project would redevelop this brownfield and allow it to be reused for industrial purposes.

FACILITY DESCRIPTION

4. The electric power supply system produces and distributes power, usually from several power sources at once, 

such as power plants that burn fuels to produce electricity, hydroelectric dams and wind turbine farms. The 

amount of power required at any time varies depending on demand. Certain power plants produce a fairly 

steady amount of power to meet most of the demand, while others increase or decrease their output to match 

the variations in demand. In addition to changes in demand, the availability of wind power also adds variability 

to the supply of power because wind turbines can only produce power when the wind is blowing, and wind 

power may be unexpectedly reduced if the wind dies down unexpectedly. 

5. TEC is proposing to construct a power plant that is intended to both help meet varying power demand as well 

as help fill in when wind power is reduced. As such, this plant is expected to change its power output 

frequently. Power will be produced by one 451 MW (nominal) combined-cycle combustion turbine generator

and two simple-cycle combustion turbine generators each rated at 101 MW (nominal).

6. The combustion turbine generators will normally burn natural gas, but all three can burn ultra-low sulfur 

distillate (ULSD) fuel for up to 720 hours per year each. The combined cycle combustion turbine may only 

burn ULSD during periods when natural gas is curtailed. Natural gas curtailment may occur during very cold 

winter conditions. During natural gas curtailment periods, industrial facilities and power plants such as TEC 
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 5 of 31

that can burn ULSD switch to ULSD to help ensure adequate natural gas for home heating and other critical 

uses. The two simple-cycle combustion turbines may burn ULSD at any time, with each limited to 720 hours 

per year. All of the combustion turbine generators will be equipped with emission control systems to minimize 

pollutant emissions when burning either natural gas or ULSD.

7. TEC will have two GE LMS 100 simple-cycle combustion turbine generators. A simple-cycle combustion 

turbine generator consists of a combustion turbine that powers an electric generator. These turbines are capable 

of rapid start-up to provide rapidly available load-following electric power and will be started and stopped 

frequently to match changing electric power supply and demand. The estimated number of startups and 

shutdowns per turbine is shown below:

Number per 

year while 

using ULSD

Duration of 

startup or 

shutdown on 

ULSD

Number per 

year while 

using natural 

gas

Duration of 

startup or 

shutdown on 

natural gas

Startups 400 10 minutes each 600 10 minutes each

Shutdowns 400 9 minutes each 600 11 minutes each

Total duration of startups 

and shutdowns, both fuels 330 hours per year per turbine

8. TEC will have one Mitsubishi M501-GAC combustion turbine in a combined-cycle configuration. A 

combined-cycle combustion turbine generator consists of the following: a combustion turbine engine that 

powers an electric generator; a heat recovery steam generator (HRSG) which uses heat from the combustion 

turbine engine exhaust to produce steam; a steam turbine which uses the steam from the HRSG to power 

another electric generator; and a duct burner which is located between the gas turbine engine and the HRSG to 

provide additional heat for producing steam. This turbine takes longer to start up than the simple-cycle turbines 

and will normally run for extended periods of time, with fewer startups and shutdowns per year estimated as 

follows:

Number per year

while using 

ULSD

Number per year

while using 

natural gas

Duration of 

startup or 

shutdown on 

either fuel

Hot starts 30 80 36 minutes each

Warm starts 15 40 53 minutes each

Cold starts 2 40 270 minutes each

Shutdowns 47 160 5 minutes each

Total duration of startups 

and shutdowns, both fuels 321 hours per year

9. In addition to the combustion turbines, TEC will have the following other systems that emit air pollutants:

 one auxiliary boiler that burns only natural gas, rated at 39.8 million Btu per hour, maximum operating 

time of 4,000 hours per year;

 one fire water pump engine that burns ULSD, 360 horsepower, maximum non-emergency operating 

time of 100 hours per year for testing and maintenance;

 two cooling towers, one with eight cells and one with two cells, maximum operating time of 8,760 

hours per year; and

 one 2.2 million gallon storage tank for ULSD fuel.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 6 of 31

10. TEC’s application includes the following summary of emissions from all of the air pollutant emitting units:

Emissions Summary (Including Startup/Shutdown), tons per year1

Equipment NOx CO PM10

2 PM2.5 SO2 VOC H2SO4 HAP CO2e

(GHG)

CO2

One

CombinedCycle 

Combustion 

Turbine

138.2 537.7 109.3 109.3 23.6 176.4 7.2 8.3 1,841,172 1,839,443

Two

SimpleCycle 

Combustion 

Turbines

85.1 101.1 87.1 87.1 10.9 33.7 11.1 3.7 877,018 876,197

Cooling 

Tower

- - 0.6 0.6 - - - - - -

Auxiliary 

Boiler 

2.8 3.2 0.4 0.4 0 0.4 Neg30.1 9,313 9,304

ULSD 

Storage 

Tank 

- - - - - 0.4 - - - -

Fire Pump 0.1 0.01 0.003 0.003 0.01 0.004 Neg 0.001 19 19

Total 226.2 642.0 197.4 197.4 34.6 210.9 18.3 12.1 2,727,522 2,724,963

1) Not including aggregate insignificant emissions.

2) Particulate matter (PM) emissions are assumed equal to PM10

3) Negligible
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 7 of 31

EMISSIONS UNIT AND POLLUTION CONTROL DEVICE IDENTIFICATION

11. The emissions units at this facility are the following: 

Emissions Unit 

Identification

Emissions Unit Description Emission 

Control Device 

Identification

Emission Control Device 

Description

EU1 Mitsubishi M501-GAC 

combustion turbine, combined 

cycle configuration with duct 

burner.

Dry low-NOx burners on gas;

Water injection on ULSD.

Combustion turbine 2,988 

MMBtu*/hr, natural gas or ULSD

Duct burner 499 MMBtu/hr, 

natural gas only

CCCD1

CCCD2

SCR with aqueous 

ammonia injection for 

NOx control

Oxidation catalyst for CO, 

VOC control

EU2 GE LMS-100 combustion turbine, 

simple cycle with water injection.

845 MMBtu/hr, natural gas or 

ULSD

SC1CD1

SC1CD2

SCR with aqueous 

ammonia injection for 

NOx control

Oxidation catalyst for CO, 

VOC control

EU3 GE LMS-100 combustion turbine, 

simple cycle with water injection.

845 MMBtu/hr, natural gas or 

ULSD

SC2CD1

SC2CD2

SCR with aqueous 

ammonia injection for 

NOx control

Oxidation catalyst for CO, 

VOC control

EU4 Cooling towers NA NA

EU5 Auxiliary boiler, 39.8 MMBtu/hr, 

natural gas, with Low-NOx 

burners and FGR 

NA NA

EU6 Storage tank, 2.2 million gallons, 

fixed roof, ULSD (vapor pressure 

0.0055 psia)

NA NA

EU7 Fire water pump powered by 360 

hp CI RICE, ULSD

NA NA

* All heat values are based on higher heating value (HHV)

12. Categorically insignificant activities include the following: 

 Constituents of a chemical mixture present at less than 1% by weight of any chemical or compound 

regulated under OAR Chapter 340, Divisions 200 through 268, excluding Divisions 248 and 262, or less 

than 0.1% by weight of any carcinogen listed in the U.S. Department of Health and Human Service's 

Annual Report on Carcinogens when usage of the chemical mixture is less than 100,000 pounds/year

 Evaporative and tail pipe emissions from on-site motor vehicle operation

 Distillate oil, kerosene, and gasoline fuel burning equipment rated at less than or equal to 0.4 million Btu/hr

 Natural gas and propane burning equipment rated at less than or equal to 2.0 million Btu/hr

 Office activities

 Food service activities

 Janitorial activities

 Personal care activities
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 8 of 31

 Groundskeeping activities including, but not limited to building painting and road and parking lot 

maintenance

 On-site recreation facilities

 Instrument calibration

 Maintenance and repair shop

 Air cooling or ventilating equipment not designed to remove air contaminants generated by or released 

from associated equipment

 Refrigeration systems with less than 50 pounds of charge of ozone depleting substances regulated under 

Title VI, including pressure tanks used in refrigeration systems but excluding any combustion equipment 

associated with such systems

 Bench scale laboratory equipment and laboratory equipment used exclusively for chemical and physical 

analysis, including associated vacuum producing devices but excluding research and development facilities

 Temporary construction activities

 Accidental fires

 Air vents from air compressors

 Air purification systems

 Continuous emissions monitoring vent lines

 Demineralized water tanks

 Pre-treatment of municipal water, including use of deionized water purification systems

 Electrical charging stations

 Instrument air dryers and distribution

 Process raw water filtration systems

 Routine maintenance, repair, and replacement such as anticipated activities most often associated with and 

performed during regularly scheduled equipment outages to maintain a plant and its equipment in good 

operating condition, including but not limited to steam cleaning, abrasive use, and woodworking

 Electric motors

 Storage tanks, reservoirs, transfer and lubricating equipment used for ASTM grade distillate or residual 

fuels, lubricants, and hydraulic fluids

 On-site storage tanks not subject to any New Source Performance Standards (NSPS), including 

underground storage tanks (UST), storing gasoline or diesel used exclusively for fueling of the facility's 

fleet of vehicles

 Natural gas, propane, and liquefied petroleum gas (LPG) storage tanks and transfer equipment

 Pressurized tanks containing gaseous compounds

 Emissions from wastewater discharges to publicly owned treatment works (POTW) provided the source is 

authorized to discharge to the POTW, not including on-site wastewater treatment and/or holding facilities

 Storm water settling basins

 Fire suppression and training

 Paved roads and paved parking lots within an urban growth boundary

 Hazardous air pollutant emissions of fugitive dust from paved and unpaved roads except for those sources 

that have processes or activities that contribute to the deposition and entrainment of hazardous air 

pollutants from surface soils

 Health, safety, and emergency response activities

 Emergency generators and pumps used only during loss of primary equipment or utility service due to 

circumstances beyond the reasonable control of the owner or operator, or to address a power emergency as 

determined by DEQ

 Non-contact steam vents and leaks and safety and relief valves for boiler steam distribution systems

 Non-contact steam condensate flash tanks

 Non-contact steam vents on condensate receivers, deaerators and similar equipment

 Boiler blowdown tanks

 Industrial cooling towers that do not use chromium-based water treatment chemicals

 Oil/water separators in effluent treatment systems

 Combustion source flame safety purging on startup
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 9 of 31

NEW SOURCE REVIEW (NSR) AND PREVENTION OF SIGNIFICANT DETERIORATION (PSD)

13. The proposed facility is subject to NSR and PSD (OAR 340-224-0060 and 0070) as described in the following 

paragraphs.

14. The maximum estimated criteria pollutant emissions from the proposed facility are listed below along with the 

Significant Emission Rate (SER) for each pollutant:

Pollutant Maximum Estimated Criteria 

Pollutant Emissions

including aggregate 

insignificant emissions,

tons/year

Significant Emission Rate 

(SER)

tons/year

PM10 198 15

PM2.5 198 10

NOx2227 40

CO 643 100

SO2

3

36 40

VOC4212 40

H2SO4 (sulfuric acid mist) 19 7

GHG (CO2e) 2,730,000 75,000

CO2 2,724,9631100

1) Not including aggregate insignificant emissions

2) NOx is regulated as NOx itself, and also as a precursor to both ozone and PM2.5.

3) SO2 is regulated as SO2 itself, and also as a precursor to PM2.5.

4) VOC is regulated as precursor to ozone.

15. The facility is located in a Maintenance Area for ozone and CO. Within a Maintenance Area a proposed 

facility that will emit the Maintenance Area pollutants at a rate equal to or greater than the SER is subject to 

NSR for those pollutants. For the proposed facility, those pollutants are:

15.a. NOx (as an ozone precursor);

15.b. CO; and

15.c. VOC (ozone precursor).

16. The facility is classified as a Federal Major Source because emissions of CO will exceed 250 tons per year and 

GHG and CO2 will exceed 100,000 tons per year and 100 tons per year, respectively. Within an

attainment/unclassified area a proposed facility that is classified as a Federal Major Source and will emit the

attainment/unclassified area pollutants at a rate equal to or greater than the SER is subject to PSD for those 

pollutants. For the proposed facility, those pollutants are:

16.a. PM10;

16.b. PM2.5;

16.c. NOx (as NOx and as a PM2.5 precursor);

16.d. H2SO4; and

16.e. GHG

17. The facility is not subject to either NSR or PSD for SO2 as itself or as a PM2.5 precursor because the emissions 

are less than the SER.

NSR Requirements

18. Within the Portland Maintenance Area, the requirements specified in OAR 340-224-0060(1) through (4) must 

be met for NOx (as an ozone precursor), CO, and VOC (ozone precursor). The following paragraphs 

summarize the requirements and how the applicant met them.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 10 of 31

19. OAR 340-224-0060(1):

19.a. Best Available Control Technology (BACT). The owner or operator must apply BACT for each 

maintenance pollutant or precursor(s) emitted at or above a significant emission rate (SER). BACT 

applies separately to the maintenance pollutant or precursor(s) if emitted at or above a SER over the 

netting basis. The requirement for BACT applies to each emissions unit that emits the maintenance 

pollutant or precursor(s).

19.b. The applicant performed the required BACT analyses; see the BACT DETERMINATION section of 

this report beginning with paragraph 27.

20. OAR 340-224-0060(2):

20.a. Air Quality Protection: Growth Allowance. The requirements of this section may be met in whole or 

in part in an ozone or carbon monoxide maintenance area with an allocation by the Department from a 

growth allowance, if available, in accordance with the applicable maintenance plan in the SIP adopted 

by the Commission and approved by EPA. An allocation from a growth allowance used to meet the 

requirements of this section is not subject to the Requirements for Demonstrating a Net Air Quality 

Benefit in OAR 340-225-0090. 

20.b. The applicant requested, and was granted, allocations from the NOx, VOC and CO growth allowances 

for the Portland Maintenance Area of 227 tons/year NOx, 212 tons/year VOC and 643 tons/year CO.

The allocations are sufficient to cover the requested PSELs and, pursuant to OAR 340-224-

0060(2)(b), the requirements for Net Air Quality Benefit in OAR 340-225-0090 are not applicable.

21. OAR 340-224-0060(3):

21.a. The owner or operator must provide an air quality analysis in accordance with OAR 340-225-0050(1) 

and (2), and 340-225-0060. 

21.b. The applicant performed the required air quality analyses; see the AIR QUALITY ANALYSIS

section of this report beginning with paragraph 43.

22. OAR 340-224-0060(4):

22.a. The owner or operator of a federal major source subject to this rule must provide an analysis of the air 

quality impacts for the proposed source or modification in accordance with OAR 340-225-0050(3) 

and 340-225-0070. In addition to the provisions of this section, provisions of section 340-224-0070 

also apply to federal major sources. 

22.b. The applicant performed the required air quality analyses; see the AIR QUALITY ANALYSIS

section of this report beginning with paragraph 43.

PSD Requirements

23. The greater Portland area, including Troutdale, is classified as an attainment or unclassified area for all 

regulated pollutants except ozone and CO. For PM10, PM2.5, NOx (as NOx and as a PM2.5 precursor), 

H2SO4, and GHG the requirements specified in OAR 340-224-0070(1) through (3) must be met. The 

following paragraphs summarize the requirements and how the applicant met them.

24. OAR 340-224-0070(1):
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 11 of 31

24.a. Best Available Control Technology (BACT). The owner or operator must apply BACT for each 

maintenance pollutant or precursor(s) emitted at or above a significant emission rate (SER). BACT 

applies separately to the maintenance pollutant or precursor(s) if emitted at or above a SER over the 

netting basis. The requirement for BACT applies to each emissions unit that emits the maintenance 

pollutant or precursor(s).

24.b. The applicant performed the required BACT analyses; see the BACT DETERMINATION section of 

this report beginning with paragraph 27.

25. OAR 340-224-0070(2):

25.a. The owner or operator must provide an air quality analysis in accordance with OAR 340-225-0050 

through 340-225-0070.

(a) For increases of direct PM2.5 or PM2.5 precursors equal to or greater than the significant 

emission rate, the owner or operator must provide an analysis of PM2.5 air quality impacts based 

on all increases of direct PM2.5 and PM2.5 precursors.

(b)The owner or operator of any source subject to this rule that significantly impacts air quality in 

a designated nonattainment or maintenance area must meet the requirements of net air quality 

benefit in 340-225-0090. 

25.b. The applicant performed the required air quality analyses; see the AIR QUALITY ANALYSIS

section of this report beginning with paragraph 43. PM2.5 and PM2.5 precursor air quality impacts 

were analyzed.

25.c. The applicant is not required to meet the requirements of net air quality benefit in OAR 340-225-0090 

for maintenance area pollutants (NOx, VOC and CO) because allocations from the NOx, VOC and 

CO growth allowances for the Portland Maintenance Area were obtained. When growth allowance 

allocations are obtained the requirements for Net Air Quality Benefit in OAR 340-225-0090 are not 

applicable.

26. OAR 340-224-0070(3):

26.a. Air Quality Monitoring: The owner or operator of a source subject to this rule must conduct ambient 

air quality monitoring in accordance with the requirements in OAR 340-225-0050. 

26.b. OAR 340-225-0050(a)(A) states: “ When referred to this rule by division 224, the owner or operator 

of a source must submit with the application an analysis of ambient air quality in the area impacted by 

the proposed project. This analysis, which is subject to the Department's approval, must be conducted 

for each pollutant potentially emitted at a significant emission rate by the proposed source or 

modification. The analysis must include continuous air quality monitoring data for any pollutant that 

may be emitted by the source or modification, except for volatile organic compounds. The data must 

relate to the year preceding receipt of the complete application and must have been gathered over the 

same time period. The Department may allow the owner or operator to demonstrate that data 

gathered over some other time period would be adequate to determine that the source or modification 

would not cause or contribute to a violation of an ambient air quality standard or any applicable 

pollutant increment.” (Emphasis added.)

26.c. OAR 340-225-0050(a)(C) states in part: “The Department may exempt the owner or operator of a 

proposed source or modification from preconstruction monitoring for a specific pollutant if the owner 

or operator demonstrates that the air quality impact from the emissions increase would be less than the 

amounts listed below or that modeled competing source concentration (plus General Background 

Concentration) of the pollutant within the Source Impact Area are less than” the significant 

monitoring concentrations listed in the rule
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 12 of 31

26.d. DEQ has waived the requirement to perform air quality monitoring for the following reasons:

26.d.i. Carbon monoxide: CO is monitored by DEQ in Portland at SE 57th and Lafayette and the 

data is considered representative of the proposed location for this facility. In addition, the 

applicant obtained an allocation from the growth allowance sufficient to cover the requested 

PSEL.

26.d.ii. Nitrogen dioxide: NOx is monitored by DEQ in Portland at SE 57th and Lafayette and the 

data is considered representative of the proposed location for this facility. In addition, the 

applicant modeled less than the significant monitoring concentration and obtained an 

allocation from the growth allowance sufficient to cover the requested PSEL.

26.d.iii. PM10: PM10 is monitored by DEQ in Portland at SE 57th and Lafayette and the data is 

considered representative of the proposed location for this facility. In addition, the applicant 

modeled less than the significant monitoring concentration.

26.d.iv. PM2.5: PM2.5 is monitored by DEQ in Portland at SE 57th and Lafayette and the data is 

considered representative of the proposed location for this facility.

26.d.v. Ozone: Ozone is monitored by DEQ in Portland at SE 57th and Lafayette and the data is 

considered representative of the proposed location for this facility. In addition, the applicant 

obtained an allocation from the growth allowances for VOC and NOx sufficient to cover the 

requested PSELs.

BACT DETERMINATION

27. The definition of Best Available Control Technology in OAR 340-200-0020 reads as follows:

"Best Available Control Technology" or "BACT" means an emission limitation, including, but not limited 

to, a visible emission standard, based on the maximum degree of reduction of each air contaminant subject 

to regulation under the Act which would be emitted from any proposed major source or major modification 

which, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other 

costs, is achievable for such source or modification through application of production processes or 

available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel 

combustion techniques for control of such air contaminant. In no event may the application of BACT result 

in emissions of any air contaminant that would exceed the emissions allowed by any applicable new source 

performance standard or any standard for hazardous air pollutant. If an emission limitation is not feasible, a 

design, equipment, work practice, or operational standard, or combination thereof, may be required. Such 

standard must, to the degree possible, set forth the emission reduction achievable and provide for 

compliance by prescribing appropriate permit conditions. 

28. BACT generally refers to both an emission limit and the control technology that must be used to achieve the 

emission limit, and is often referred to as “top-down BACT” because the analysis considers the most effective 

control options first and is designed to select the most effective control option that is technically feasible and 

which, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other 

costs, is achievable for the emitting equipment being evaluated. If the top (most effective) control option is 

eliminated because of energy, environmental or economic considerations, then the next-most effective control 

option is evaluated in turn. The most effective and feasible option that is not eliminated is chosen as BACT. 

BACT is determined by conducting a BACT analysis that involves the following steps:

Step 1 – Identify all applicable control technologies 

Step 2 – Eliminate technically infeasible options 

Step 3 – Rank the remaining control technologies by control effectiveness with the most effective at the top

Step 4 – Evaluate the most effective controls taking into account energy, environmental, and economic 

impacts and other costs, and document results

Step 5 – Select BACT
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 13 of 31

29. TEC is subject to BACT requirements for the following pollutants and equipment:

Pollutant Equipment subject to BACT

NOx Combustion turbines; auxiliary boiler; emergency fire pump engine

CO Combustion turbines; auxiliary boiler; emergency fire pump engine

VOC Combustion turbines; auxiliary boiler; emergency fire pump engine; fuel storage tank

H2SO4 Combustion turbines

PM10 Combustion turbines; auxiliary boiler; emergency fire pump engine; cooling towers

PM2.5 Combustion turbines; auxiliary boiler; emergency fire pump engine; cooling towers

GHG Combustion turbines; auxiliary boiler; emergency fire pump engine

30. TEC performed a BACT analysis for each emissions unit identified in paragraph 11 of this report, and 

proposed the following as BACT:

30.a. EU1

Mitsubishi M501-GAC combustion turbine, combined cycle configuration with duct burner.

Combustion turbine 2,988 MMBtu/hr, natural gas or ULSD; Duct burner 499 MMBtu/hr, natural gas

Pollutant Control technology reviewed 

by applicant

Control technology proposed 

by applicant

Emission limit(s) proposed by 

applicant

NOx Water injection

Steam injection

DLN combustors

Catalytic combustors (for 

example, XONONTM)

SCR

Selective non-catalytic 

reduction (SNCR)

Non-selective catalytic 

reduction (NSCR)

SCONOxTM

Utilize dry low-NOx burners 

when combusting natural gas;

Utilize water injection when 

combusting ULSD;

Utilize selective catalytic 

reduction (SCR) with aqueous 

ammonia injection at all times 

except during startup and 

shutdown;

Limit the time in startup or 

shutdown.

2.0 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting natural gas, except 

during startup and shutdown.

5.5 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting ULSD, except 

during startup and shutdown.

Startup times limited to:

4.5 hours for a cold start;

1.5 hours for a warm start; and

1.0 hour for a hot start.

Shutdown time limited to 15 

minutes.

CO Catalytic Oxidation (CatOx)

Catalytic Combustion 

(XONONTM)

DLN Burners

SCONOXTM

Oxidation catalyst;

Limit the time in startup or 

shutdown.

3.3 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting natural gas, except 

during startup and shutdown.

9.0 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting ULSD, except 

during startup and shutdown.

Startup times limited to:

4.5 hours for a cold start;

1.5 hours for a warm start; and

1.0 hour for a hot start.

Shutdown time limited to 15 

minutes.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 14 of 31

Pollutant Control technology reviewed 

by applicant

Control technology proposed 

by applicant

Emission limit(s) proposed by 

applicant

VOC Catalytic Oxidation (CatOx)

Catalytic Combustion 

(XONONTM)

DLN Burners

SCONOXTM

Oxidation catalyst;

Limit the time in startup or 

shutdown.

2.0 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting natural gas, except 

during startup and shutdown.

5.0 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting ULSD, except 

during startup and shutdown.

Startup times limited to:

4.5 hours for a cold start;

1.5 hours for a warm start; and

1.0 hour for a hot start.

Shutdown time limited to 15 

minutes.

H2SO4 Utilize only natural gas or 

ULSD fuel.

None

PM10 and 

PM2.5

Utilize only natural gas or 

ULSD fuel; Limit the time in 

startup or shutdown.

23.6 lb/hr total PM (filterable 

plus condensable) at the 

maximum firing rate, 6-hr 

average when combusting 

natural gas, except during 

startup and shutdown.

42.3 lb/hr total PM (filterable 

plus condensable) at the 

maximum firing rate, 6-hr 

average when combusting 

ULSD, except during startup 

and shutdown.

Startup times limited to:

4.5 hours for a cold start;

1.5 hours for a warm start; and

1.0 hour for a hot start.

Shutdown time limited to 15 

minutes.

GHG Carbon capture and storage 

(CCS)

Thermal efficiency

Clean fuels

Thermal efficiency

Clean fuels

1,000 lb of CO2 per gross MWh 

on a 365-day rolling average.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 15 of 31

30.b. EU2 and EU3

GE LMS-100 combustion turbines, simple cycle with water injection.

1,690 MMBtu/hr (for EU2 and EU3 combined), natural gas or ULSD.

Pollutant Control technology reviewed

by applicant

Control technology proposed 

by applicant

Emission limit(s) proposed by 

applicant

NOx Water injection

Steam injection

DLN combustors

Catalytic combustors (for 

example, XONONTM)

SCR

SNCR

NSCR

SCONOxTM

Utilize water injection when 

combusting natural gas or 

ULSD;

Utilize selective catalytic 

reduction (SCR) with aqueous 

ammonia injection at all times 

except during startup and 

shutdown;

Limit the time in startup or 

shutdown.

2.5 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting natural gas, except 

during startup and shutdown.

3.8 ppmdv at 15% O2, 3-hr 

average when combusting 

ULSD, except during startup 

and shutdown.

Startup times limited to:

10 minutes for any startup.

Shutdown time limited to 11 

minutes.

CO Catalytic Oxidation (CatOx)

Catalytic Combustion 

(XONONTM)

DLN Burners

SCONOXTM

Oxidation catalyst;

Limit the time in startup or 

shutdown.

6.0 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting natural gas, except 

during startup and shutdown.

6.0 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting ULSD, except 

during startup and shutdown.

Startup times limited to:

10 minutes for any startup.

Shutdown time limited to 11 

minutes.

VOC Catalytic Oxidation (CatOx)

Catalytic Combustion 

(XONONTM)

DLN Burners

SCONOXTM

Oxidation catalyst;

Limit the time in startup or 

shutdown.

3.5 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting natural gas, except 

during startup and shutdown.

5.0 ppmdv at 15% O2, 3-hr 

rolling average when 

combusting ULSD, except 

during startup and shutdown.

Startup times limited to:

10 minutes for any startup.

Shutdown time limited to 11 

minutes.

H2SO4 Utilize only natural gas or 

ULSD fuel.

None
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 16 of 31

Pollutant Control technology reviewed

by applicant

Control technology proposed 

by applicant

Emission limit(s) proposed by 

applicant

PM10 and 

PM2.5

Utilize only natural gas or 

ULSD fuel; Limit the time in 

startup or shutdown.

9.1 lb/hr total PM (filterable

plus condensable) at the 

maximum firing rate, 6-hr 

average when combusting 

natural gas, except during 

startup and shutdown.

22.7 lb/hr total PM (filterable 

plus condensable) at the 

maximum firing rate, 6-hr 

average when combusting 

ULSD, except during startup 

and shutdown.

Limits apply to each LMS-100 

combustion turbine.

Startup times limited to:

10 minutes for any startup.

Shutdown time limited to 11 

minutes.

GHG Carbon capture and storage 

(CCS)

Thermal efficiency

Clean fuels

Thermal efficiency

Clean fuels

1,707 lb of CO2 per gross MWh 

on a 365-day rolling average. 

Limits apply to each LMS-100 

SCCT.

30.c. EU4

Cooling Towers

Pollutant Control technology reviewed

by applicant

Control technology proposed 

by applicant

Emission limit(s) proposed by 

applicant

PM10 and 

PM2.5

Limitation of Dissolved Solids 

in Recirculating Cooling Tower 

Water

Use of Drift Eliminators

Use of drift eliminators with a 

design drift rate of 0.0005 

percent of cooling tower flow 

rate.

None.

30.d. EU5

Auxiliary boiler, 39.8 MMBtu/hr, natural gas, with Low-NOx burners and FGR

Pollutant Control technology reviewed

by applicant

Control technology proposed 

by applicant

Emission limit(s) proposed by 

applicant

NOx SCR

SNCR

NSCR

Low NOx Burner (LNB) 

Technology with flue gas 

recirculation (FGR)

LNB

Good combustion practices

Utilize Low-NOx burners and 

FGR.

0.035 lb/MMBtu, 3-hr block 

average, except during startup 

and shutdown. 

CO Utilize Low-NOx burners and 

FGR.

0.04 lb/MMBtu, 3-hr block 

average, except during startup 

and shutdown. 
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 17 of 31

Pollutant Control technology reviewed

by applicant

Control technology proposed 

by applicant

Emission limit(s) proposed by 

applicant

VOC Utilize Low-NOx burners and 

FGR.

0.005 lb/MMBtu, 3-hr block 

average, except during startup 

and shutdown.

H2SO4 Good combustion practices;

Utilize only natural gas.

None

PM10 and 

PM2.5

Good combustion practices;

Utilize only natural gas.

None

GHG Carbon capture and storage 

(CCS)

Thermal efficiency

Clean fuels

Clean fuels 117 lb CO2/MMBtu, 3-hr block 

average

30.e. EU6

Storage tank, 2.2 million gallons, fixed roof, ULSD (vapor pressure 0.0055 psia).

Pollutant Control technology reviewed

by applicant

Control technology proposed 

by applicant

Emission limit(s) proposed by 

applicant

VOC Submerged fill line;

Vapor balancing during tank 

filling.

Submerged fill line;

Vapor balancing during tank 

filling.

None

30.f. EU7

Fire water pump powered by 360 hp CI RICE, ULSD.

Pollutant Control technology reviewed

by applicant

Control technology proposed 

by applicant

Emission limit(s) proposed by 

applicant

NOx Injection Timing Retardation

Lean-burn Combustion

Selective Catalytic Reduction

Turbocharging and Aftercooling

Utilize a pump engine that 

meets the RICE NSPS 

requirements.

Lean burn combustion, good 

combustion practices, 

turbocharging and aftercooling.

None

CO Good combustion practices. Good combustion practices. None

VOC Good combustion practices. Good combustion practices. None

H2SO4 Utilize ULSD fuel;

Good combustion practices.

Utilize ULSD fuel;

Good combustion practices.

None

PM10 and 

PM2.5

Utilize ULSD fuel;

Good combustion practices.

Utilize ULSD fuel;

Good combustion practices.

None

GHG High efficiency engine High efficiency engine 163 lb CO2/MMBtu
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 18 of 31

FINAL BACT DETERMINATIONS AND AMMONIA LIMIT

31. DEQ reviewed the BACT determinations proposed by the applicant, and in summary:

31.a. DEQ agrees with the BACT determinations for EU1 (combined cycle combustion turbine and duct 

burner) and EU2 and EU3 (simple cycle combustion turbines), which are summarized above in 

paragraphs 30.a and 30.b;

31.b. DEQ agrees with the BACT determinations for emissions units EU4 through EU7 (cooling towers, 

auxiliary boiler, ULSD storage tank, and fire water pump engine), which are summarized above in 

paragraphs 30.c through 30.f.; and

31.c. Other requirements and limitations were proposed by the applicant that are not BACT requirements 

but serve to further limit emissions have been included in the draft permit and are discussed below.

EU1, EU2 and EU3 NOx

32. NOx is regulated both as NOx itself and as a substance that contributes to the formation of ozone. NOx levels 

in the Portland area are generally well below the National Ambient Air Quality Standards for NO2, but NOx 

contributes to nitrogen deposition in national forests and the Columbia River Gorge National Scenic Area 

(CRGNSA). Ozone is a pollutant of concern in the Portland area as well as in nearby national forests and the 

CRGNSA. 

33. The combustion turbines will use low-NOx combustion systems in combination with selective catalytic 

reduction (SCR) add-on NOx control systems. SCR involves a catalyst that the turbine exhaust gases pass over. 

Ammonia is injected upstream of the catalyst, and when NOx and ammonia contact the catalyst they react to 

convert NOx and ammonia (NH3) into nitrogen gas (N2) and water (H2O). The chemical reaction is not perfect 

and not all of the NOx and ammonia are converted. As more ammonia is injected, the amount of NOx 

converted increases, but at the same time more of the ammonia passes through the catalyst without being 

reacted and is emitted. Ammonia that passes through the catalyst without reacting is called “ammonia slip”. 

Thus, in general, as more ammonia is injected NOx is decreased while ammonia slip increases.

34. In addition to the NOx BACT limit, the applicant also proposed to limit ammonia slip to 5 ppm on a three-hour 

average basis. Compliance with this limit must be demonstrated by emissions testing at both full load and 

minimum normal operating load. DEQ believes this limit meets the intent of the Operation and Maintenance 

rules, OAR 340-226-0120(1), and has cited this rule as the authority for this limit.

35. Emission limits are frequently set as an average over some period of time because it is normal for emissions to 

vary up and down somewhat. There will be times when the emissions will go above the numerical limit, but at 

other times emissions will be less than the numerical limit. In addition, emissions testing normally involves 

three one-hour test runs with the test result being the average of the three runs, effectively establishing a 

default three-hour average. The facility will be in compliance with the limit if the average emissions over the 

specified time period are at or below the limit. The applicant proposed the following NOx limits and averaging 

times for the combustion turbines:

2.0 ppm while combusting natural gas and 5.5 ppm while combusting ULSD for the combined cycle 

turbine; and

2.5 ppm while combusting natural gas and 3.8 ppm while combusting ULSD for the simple cycle turbines.

These proposed limits are all at 15 percent oxygen on a three-hour rolling average basis.

36. DEQ received comments from the National Park Service (NPS) stating that the NOx limits should be applied 

on a one-hour average basis because a one-hour average is more stringent than a three-hour average. The NPS 

provided examples of facilities that had one-hour average limits.

37. DEQ requested additional information from the applicant with regard to three-hour versus one-hour average 

limits. The applicant stated that one-hour average limits are appropriate for combustion turbines that operate as 
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 19 of 31

base-load generators which operate predominantly at relatively steady power outputs, but are not appropriate 

for this facility because it is intended to operate with frequently changing output to meet changing demand or 

to fill in for changing wind power supply.

38. DEQ understands that this facility will be used to integrate with power generated by wind turbines which have 

a variable output due to (sometimes unpredictable) changes in the wind, and agrees that this facility will

experience frequent load changes. During load increases, the power output of the turbine must be increased to 

match the higher load. Increasing the power output of the turbine requires the use of extra fuel over the amount

required to run at steady-state at the higher power output, which also increases NOx production in the turbine.

The NOx emission control system will react to increased NOx by increasing ammonia injection, but there is a 

short time lag before the control system reacts, resulting in higher NOx emissions until the emission control 

system can “catch up” with the increased NOx production. With frequent load changes occurring, DEQ expects 

NOx emissions to vary frequently as well. Under these circumstances, DEQ agrees with the applicant that 

three-hour average limits are more appropriate than one-hour average limits.

EU1, EU2 and EU3 ammonia

39. Ammonia is not a regulated air pollutant, but ammonia is believed to contribute to the formation of PM2.5, and 

ammonia limits have been set in many NSR/PSD permits since the mid-1990s. The applicant proposed an 

ammonia limit of 5 ppmdv on a three-hour block average basis, with annual testing to show compliance with 

the limit. Lower ammonia limits have been established for other facilities, but these have been for facilities 

operating at steady-state, with a 5 ppm limit during non-steady-state operation. In view of this facility’s 

expected frequent load changes, DEQ agrees with the proposed limit.

EU1, EU2 and EU3 GHG

40. DEQ received comments from the National Park Service (NPS) stating that the GHG BACT limits should be 

lower than those proposed by the applicant. The NPS provided examples of facilities that had lower GHG 

emissions. DEQ requested additional information from the applicant with regard to GHG BACT limits. The 

applicant stated that lower GHG limits were not appropriate for this facility because it is intended to operate 

with frequently changing loads rather than operating at relatively steady loads, and this mode of operation 

would make it difficult to meet lower limits. DEQ understands that this facility will be used to integrate with 

power generated by wind turbines which have a variable output due to changes in the wind, and will therefore 

experience frequent load changes.

41. As explained above in the NOx discussion, DEQ understands that this facility will be used to integrate with 

power generated by wind turbines which have a variable output due to changes in the wind, and agrees that this 

facility will experience frequent load changes. During load increases, the power output of the turbine must be 

increased to match the higher load. Increasing the power output of the turbine requires the use of extra fuel 

over the amount required to run at steady-state at the higher power output, which also increases GHG 

emissions over the steady-state emission rate. In addition, the GHG emission limit proposed by the applicant 

accounts for the use of ULSD, which has higher GHG emissions, up to 720 hours per year in each turbine. 

Because of the frequent load changes that this facility will experience and the use of ULSD, DEQ agrees with 

the GHG limits proposed by the applicant.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 20 of 31

Proposed BACT and Ammonia Summary

42. The proposed BACT limits are summarized in the tables below:

42.a. EU1

Mitsubishi M501-GAC combustion turbine, combined cycle configuration with duct burner.

Combustion turbine 2,988 MMBtu/hr, natural gas or ULSD; Duct burner 499 MMBtu/hr, natural gas

Pollutant Control technology Proposed BACT Limits

NOx Utilize dry low-NOx burners when 

combusting natural gas;

Utilize water injection when 

combusting ULSD;

Utilize selective catalytic reduction 

(SCR) with aqueous ammonia 

injection at all times except during 

startup and shutdown;

Limit the time in startup or shutdown.

2.0 ppmdv at 15% O2, 3-hr rolling average when combusting 

natural gas, except during startup and shutdown.

5.5 ppmdv at 15% O2, 3-hr rolling average when combusting 

ULSD, except during startup and shutdown.

Startup1times limited to:

4.5 hours for a cold start;

1.5 hours for a warm start; and

1.0 hour for a hot start.

Shutdown time limited to 15 minutes.

Ammonia 5 ppmdv, 3-hr block average

CO Oxidation catalyst;

Limit the time in startup or shutdown.

3.3 ppmdv at 15% O2, 3-hr rolling average when combusting 

natural gas, except during startup and shutdown.

9.0 ppmdv at 15% O2, 3-hr rolling average when combusting 

ULSD, except during startup and shutdown.

Startup times limited to:

4.5 hours for a cold start;

1.5 hours for a warm start; and

1.0 hour for a hot start.

Shutdown time limited to 15 minutes.

VOC Oxidation catalyst;

Limit the time in startup or shutdown.

2.0 ppmdv at 15% O2, 3-hr rolling average when combusting 

natural gas, except during startup and shutdown.

5.0 ppmdv at 15% O2, 3-hr rolling average when combusting 

ULSD, except during startup and shutdown.

Startup times limited to:

4.5 hours for a cold start;

1.5 hours for a warm start; and

1.0 hour for a hot start.

Shutdown time limited to 15 minutes.

H2SO4 Utilize only natural gas or ULSD fuel. None

PM10 and 

PM2.5

Utilize only natural gas or ULSD fuel; 

Limit the time in startup or shutdown.

23.6 lb/hr total PM (filterable plus condensable) at the 

maximum firing rate, 6-hr average when combusting natural 

gas, except during startup and shutdown.

42.3 lb/hr total PM (filterable plus condensable) at the 

maximum firing rate, 6-hr average when combusting ULSD, 

except during startup and shutdown.

Startup times limited to:

4.5 hours for a cold start;

1.5 hours for a warm start; and

1.0 hour for a hot start.

Shutdown time limited to 15 minutes.

GHG None 1,000 lb of CO2 per gross MWh on a 365-day rolling average.

 

1

Startup and shutdown times are worst case; average times are expected to be shorter in some cases. See Detail 

Sheets.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 21 of 31

42.b. EU2 and EU3

GE LMS-100 combustion turbines, simple cycle with water injection.

1,690 MMBtu/hr (for EU2 and EU# combined), natural gas or ULSD.

Pollutant Control technology Proposed BACT Limits (apply separately to each LMS100 simple cycle combustion turbine)

NOx Utilize water injection when 

combusting natural gas or ULSD;

Utilize selective catalytic reduction 

(SCR) with aqueous ammonia 

injection at all times except during 

startup and shutdown;

Limit the time in startup or shutdown.

2.5 ppmdv at 15% O2, 3-hr rolling average when combusting 

natural gas, except during startup and shutdown.

3.8 ppmdv at 15% O2, 3-hr rolling average when combusting 

ULSD, except during startup and shutdown.

Startup2times limited to:

10 minutes for any startup.

Shutdown time limited to 11 minutes.

Ammonia 5 ppmdv, 3-hr rolling average

CO Oxidation catalyst;

Limit the time in startup or shutdown.

6.0 ppmdv at 15% O2, 3-hr rolling average when combusting 

natural gas, except during startup and shutdown.

6.0 ppmdv at 15% O2, 3-hr rolling average when combusting 

ULSD, except during startup and shutdown.

Startup times limited to:

10 minutes for any startup.

Shutdown time limited to 11 minutes.

VOC Oxidation catalyst;

Limit the time in startup or shutdown.

3.5 ppmdv at 15% O2, 3-hr rolling average when combusting 

natural gas, except during startup and shutdown.

5.0 ppmdv at 15% O2, 3-hr rolling average when combusting 

ULSD, except during startup and shutdown.

Startup times limited to:

10 minutes for any startup.

Shutdown time limited to 11 minutes.

H2SO4 Utilize only natural gas or ULSD fuel. None

PM10 and 

PM2.5

Utilize only natural gas or ULSD fuel; 

Limit the time in startup or shutdown.

9.1 lb/hr total PM (filterable plus condensable) at the 

maximum firing rate, 6-hr average when combusting natural 

gas, except during startup and shutdown.

22.7 lb/hr total PM (filterable plus condensable) at the 

maximum firing rate, 6-hr average when combusting ULSD, 

except during startup and shutdown.

Startup times limited to:

10 minutes for any startup.

Shutdown time limited to 11 minutes.

GHG 1,707 lb of CO2 per gross MWh on a 365-day rolling average. 

42.c. EU4

Cooling Towers

Pollutant Control technology Proposed BACT Limits

PM10 and 

PM2.5

Use of drift eliminators with a design 

drift rate of 0.0005 percent of cooling 

tower flow rate.

None.

 

2

Startup and shutdown times are worst case; average times are expected to be shorter in some cases. See Detail 

Sheets.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 22 of 31

42.d. EU5

Auxiliary boiler, 39.8 MMBtu/hr, natural gas, with Low-NOx burners and FGR

Pollutant Control technology Proposed BACT Limits

NOx Utilize Low-NOx burners and FGR. 0.035 lb/MMBtu, 3-hr block average, except during startup 

and shutdown.

CO Utilize Low-NOx burners and FGR. 0.04 lb/MMBtu, 3-hr block average, except during startup and 

shutdown. 

VOC Utilize Low-NOx burners and FGR. 0.005 lb/MMBtu, 3-hr block average, except during startup 

and shutdown. 

H2SO4 Good combustion practices;

Utilize only natural gas.

None

PM10 and 

PM2.5

Good combustion practices;

Utilize only natural gas.

None

GHG 117 lb CO2/MMBtu, 3-hr block average

42.e. EU6

Storage tank, 2.2 million gallons, fixed roof, ULSD (vapor pressure 0.0055 psia).

Pollutant Control technology Proposed BACT Limits

VOC Submerged fill line;

Vapor balancing during tank filling.

None

42.f. EU7

Fire water pump powered by 360 hp CI RICE, ULSD.

Pollutant Control technology Proposed BACT Limits

NOx Utilize a pump engine that meets the 

RICE NSPS requirements.

Lean burn combustion, good 

combustion practices, turbocharging 

and aftercooling.

None

CO Good combustion practices. None

VOC Good combustion practices. None

H2SO4 Utilize ULSD fuel;

Good combustion practices.

None

PM10 and 

PM2.5

Utilize ULSD fuel;

Good combustion practices.

None

GHG Utilize energy efficient engine 163 lb CO2/MMBtu
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 23 of 31

AIR QUALITY ANALYSIS

43. TEC performed the air quality analysis required by OAR 340-224-0060(3) and -0070(2), and in accordance 

with OAR 340-225-0050 through 340-225-0070. The analysis included the following:

Analysis Pollutant Time period

Class II area increments NO2

PM10 and PM2.5

Annual

Annual and 24 hour

NAAQS NO2

PM10 and PM2.5

Annual and 1 hour

Annual and 24 hour

Class I area increments NO2

PM10 and PM2.5

Annual

Annual and 24 hour

Class I Air Quality Related 

Values (AQRV)

NOx

SOx, including H2SO4

PM10

Annual and 24 hour

Voluntary AQRV assessment 

of the Columbia River Gorge 

National Scenic Area

NOx

SOx, including H2SO4

PM10

Annual and 24 hour

Oregon Department of Energy 

Protected Area Analysis 

(secondary NAAQS)

NO2

PM10 and PM2.5

Annual and 24 hour

44. The air quality analysis was reviewed by DEQ and approved. The air quality analysis review report is attached 

to the end of this report.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 24 of 31

EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECORDKEEPING

Oregon Administrative Rules

45. TEC is subject to the emissions standards in the Oregon Administrative Rules (OARs) listed in the table below.

Emissions 

unit

OAR Summary of rule requirement Notes

Facility-wide 340-208-0210(2) Take reasonable precautions to prevent 

particulate matter from becoming airborne.

340-208-0300(1) Do not cause a nuisance.

340-208-0450 Do not emit particulate matter larger than 250 

microns in size so as to create an observable 

deposition upon the real property of another 

person.

340-228-0110 No person shall sell, distribute, use, or make 

available for use, any distillate fuel oil 

containing more than the following 

percentages of sulfur:

(1) ASTM Grade 1 fuel oil -- 0.3 percent by 

weight.

(2) ASTM Grade 2 fuel oil -- 0.5 percent by 

weight.

The limits in this rule have 

not been included in the 

permit because TEC has 

agreed to use only natural 

gas and ultra-low sulfur 

distillate (ULSD) fuel. The 

ULSD has a maximum 

sulfur content of 15 ppm, 

which is more stringent 

than the limits in OAR 

340-228-0110 and 

compliance with the 15 

ppm limit will ensure 

compliance with OAR 

340-228-0110.

Combinedcycle 

combustion 

turbine

340-208-0110(2) Visible emissions: no more than three 

minutes in any one hour equal to or greater 

than 20% opacity.

340-208-0600 Visible emissions: Do not allow any nonfuel-burning-equipment to discharge any air 

contaminant that is 20 percent opacity or 

greater for more than 30 seconds in any one 

hour.

Combustion turbines 

operating without ductfiring are non-fuel-burning 

equipment.

340-226-

0210(1)(b) (nonfuel burning)

and

340-228-

0210(1)(b) (fuel 

burning)

Particulate Matter: no emissions in excess of

0.1 grains per standard cubic foot for new 

sources. 

Both rules apply.

Combustion turbines 

operating without ductfiring are non-fuel-burning 

equipment. The duct 

burner is fuel burning 

equipment.

Simple-cycle 

combustion 

turbines

340-208-0110(2) Visible emissions: no more than three 

minutes in any one hour equal to or greater 

than 20% opacity.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 25 of 31

Emissions 

unit

OAR Summary of rule requirement Notes

340-208-0600 Visible emissions: Do not allow any nonfuel-burning-equipment to discharge any air 

contaminant that is 20 percent opacity or 

greater for more than 30 seconds in any one 

hour.

Combustion turbines are 

non-fuel-burning 

equipment.

340-226-

0210(1)(b)

Particulate Matter: no emissions in excess of

0.1 grains per standard cubic foot for new 

sources. 

This rule does not apply to 

fuel burning equipment; 

Combustion turbines are 

non-fuel-burning 

equipment.

Auxiliary 

boiler

340-208-0110(2) Visible emissions: no more than three 

minutes in any one hour equal to or greater 

than 20% opacity.

340-228-

0210(1)(b)

No person shall cause, suffer, allow, or 

permit the emission of particulate matter, 

from any fuel burning equipment in excess 

of:

(b) 0.1 grains per standard cubic foot for 

sources installed, constructed, or modified 

after June 1, 1970. 

Fire pump 

engine

340-208-0110(2) Visible emissions: no more than three 

minutes in any one hour equal to or greater 

than 20% opacity.

340-208-0600 Visible emissions: Do not allow any nonfuel-burning-equipment to discharge any air 

contaminant that is 20 percent opacity or 

greater for more than 30 seconds in any one 

hour.

RICE are non-fuel-burning 

equipment.

340-226-

0210(1)(b)

Particulate Matter: no emissions in excess of

0.1 grains per standard cubic foot for new 

sources. 

This rule does not apply to 

fuel burning equipment; 

RICE are non-fuel-burning 

equipment.

46. TEC is not subject to OAR 340-232-0150, which applies to organic liquid storage vessels, because the vapor 

pressure of ULSD is less than the vapor pressure threshold of 10.5 kPa (1.52 psia) in the rule.

New Source Performance Standards (NSPS)

47. TEC is subject to the New Source Performance Standards (NSPS) in 40 CFR Part 60 listed in the table below.

Equipment Part 60 Subpart Description Notes

Auxiliary 

Boiler

Dc Standards for steam generating units 

(boilers), 10 to 100 MMBtu/hr.

Fire pump 

engine

IIII Standards for stationary compressionignition internal combustion engines

Combustion 

turbines

KKKK Standards for stationary combustion turbines
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 26 of 31

Equipment Part 60 Subpart Description Notes

Combinedcycle 

combustion 

turbine

TTTT GHG standards for fossil-fuel fired electrical 

generating units

Proposed in 2012 

but not yet 

promulgated.

48. NSPS Subpart Kb, Standards for volatile organic liquids storage vessels is not applicable to the ULSD storage 

tank because the vapor pressure of ULSD is less than the vapor pressure threshold of 3.5 kPa (0.51 psia).

49. NSPS Subpart TTTT, Standards for GHG emissions for new electric utility generating units, is proposed at this 

time; TEC will likely be subject to this standard when it is promulgated by EPA.

NSPS Subpart Dc

50. The auxiliary boiler, EU5, is subject to the NSPS for small industrial-commercial-institutional steam 

generating units, 40 CFR Part 60 Subpart Dc.

50.a. Subpart Dc (§ 60.42c and § 60.43c) does not specify any emission limits for boilers that combustion 

only natural gas;

50.b. Subpart Dc (§ 60. 48c(g)(1) or (2)) requires the owner or operator to record and maintain records of 

the amount of each fuel combusted during each operating day, or as an alternative each calendar 

month.

NSPS Subpart IIII

51. The fire pump engine, EU7, is subject to the NSPS for compression ignition internal combustion engines, 40 

CFR Part 60 Subpart IIII. Subpart IIII specifies the following requirements:

51.a. § 60.4205 and Table 4 to Subpart IIII of Part 60 specify the following emission limits for the engine:

Maximum engine power Model year(s) NMHC + NOX CO PM

225≤KW<450 (300≤HP<600) 2009+ 4.0 g/kWh

(3.0 g/bhp-hr)

0.20 g/kWh

(0.15 g/bhp-hr)

51.b. § 60.4207 and § 80.510 specify that the sulfur content of the fuel must be 15 ppm maximum.

51.c. § 60.4211(c) states that the owner or operator must comply by purchasing an engine certified to the 

emission standards; emission testing is not required.

51.d. § 60.4211 also specifies operating requirements, as well as a limit of 100 hours per calendar year for 

non-emergency use. Emergency use is unlimited.

51.e. § 60.4214(b) states that an initial notification is not required, and states that the owner or operator 

must keep records of the time of operation of the engine and the reason the engine was in operation 

during that time.

NSPS Subpart KKKK

52. The combustion turbines, EU1, EU2 and EU3, are subject to the NSPS for stationary combustion turbines, 40 

CFR Part 60 Subpart KKKK. Subpart KKKK specifies the following requirements:

52.a. § 60.4330(a)(1) and (2) specify the following emission limits for SO2:

52.a.i. do not cause to be discharged into the atmosphere any gases which contain SO2 in excess of 

110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour (lb/MWh)) gross output; or

52.a.ii. do not burn any fuel which contains total potential sulfur emissions in excess of 26 ng SO2 /J 

(0.060 lb SO2 /MMBtu) heat input.

52.b. 40 CFR 60.4320, Table 1, 60.4325, and 60.4380(b)(1) specify the following emission limits for NOx:
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 27 of 31

52.b.i. 15 ppm at 15 percent O2 or 54 ng/J of useful output (0.43 lb/MWh) while combusting 

natural gas; and

52.b.ii. 42 ppm at 15 percent O2 or 160 ng/J of useful output (1.3 lb/MWh) while combusting 

ULSD.

52.c. 40 CFR 60.4335(b) and 60.4340(b)(1) require that NOx emissions be monitored with a continuous 

emissions monitoring system.

NSPS Subpart TTTT

53. Subpart TTTT was proposed in 2012 but had not been promulgated as of the date this permit was placed on 

public notice. 

53.a. As proposed, Subpart TTTT would establish a limit of 1,000 lb CO2/MWh on a 12-operating month 

annual average basis for combined-cycle combustion turbine electrical generating units.

53.b. As proposed, Subpart TTTT will apply to units that began construction after the NSPS was proposed, 

and therefore will apply to EU1 when it is promulgated. 

53.c. A requirement to comply with Subpart TTTT is included in the permit.

National Emissions Standards for Hazardous Air Pollutants (NESHAP)

54. TEC is subject to the National Emissions Standards for Hazardous Air Pollutants (NESHAPs) in 40 CFR Part 

63 listed in the table below.

Equipment Part 63 Subpart Description Notes

Fire pump 

engine

ZZZZ Standards for reciprocating internal 

combustion engines (RICE)

55. NESHAP Subpart JJJJJJ, Standards for boilers at area sources, is not applicable to this facility.

55.a. The auxiliary boiler is not subject to Subpart JJJJJJ because boilers that burn only natural gas are 

exempt from this regulation per 40 CFR 63.11195(e) and 40 CFR 63.11237 (definitions).

55.b. The duct burner is not subject to Subpart JJJJJJ because waste heat boilers including duct burners and 

heat recovery steam generators are not subject to Subpart JJJJJJ pursuant to 40 CFR 63.11195 and 40 

CFR 63.11237 (definitions of boiler and waste heat boiler).

56. NESHAP Subpart YYYY, Standards for stationary combustion turbines, is not applicable to the combustion 

turbines because this facility is not a major source of HAP emissions.

NESHAP Subpart ZZZZ

57. NESHAP Subpart ZZZZ, Standards for reciprocating internal combustion engines (RICE), is applicable to the 

fire pump engine. However, 40 CFR 63.6590(c) and (c)(1) state the following:

57.a. A new stationary RICE located at an area source must meet the requirements of 40 CFR Part 63, 

Subpart ZZZZ by meeting the requirements of NSPS 40 CFR Part 60 Subpart IIII for compression 

ignition engines (addressed in paragraph 51 of this report); and 

57.b. No further requirements apply for such engines under 40 CFR Part 63, Subpart ZZZZ.

Acid Rain

58. Emission Units EU1, EU2 and EU3 are subject to the Acid Rain Program as new units pursuant to 40 CFR 

72.6(a)(3)(i) and OAR 340-228-0300. This classifies them as “affected units” for purposes of the program.

The Acid Rain Program requirements in 40 CFR Parts 72, 73, and 75 apply to these three affected units. The 

permittee must submit a separate Acid Rain permit application at least 24 months before the date on which the 
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 28 of 31

first affected unit commences operation. Under the Acid Rain Program, the permittee will be required to 

monitor and report SO2 and NOx emissions from the affected units and obtain allowances equal to their annual 

SO2 emissions. 40 CFR Part 72 imposes the requirements associated with obtaining and certifying compliance 

with an Acid Rain permit. 40 CFR 73 contains the Acid Rain Program requirements related to obtaining SO2

allowances. 40 CFR Part 75 contains the Acid Rain Program monitoring and reporting requirements. Because 

the affected units do not burn coal, the NOx emission reduction program in 40 CFR Part 76 does not apply.

The permit includes the Acid Rain Program NOx and SO2 monitoring requirements (conditions 37, 40, 42 and 

46) because those are closely related to other requirements in the permit. The remainder of the Acid Rain 

Program requirements will be addressed in the Acid Rain permit. Once issued, the Acid Rain permit will be 

appended to this permit. 

Accidental Release Prevention (Part 68 and Section 112(r))

59. TEC is not subject to the Accidental Release Prevention requirements of 40 CFR Part 68 (Section 112(r) of the 

Clean Air Act and OAR 340-244-0230) and is not required to submit a Risk Management Plan because no 

substances subject to this regulation will be stored on site at more than the threshold quantity. Anhydrous 

ammonia and ammonia solutions of 20 percent or greater are listed substances subject to these regulations, and 

TEC will use ammonia injection for the Selective Catalytic Reduction (SCR) emission control systems for the 

combustion turbines. However, TEC will use aqueous ammonia solution at a concentration of less than 20 

percent and is therefore not subject.

Insignificant emission units

60. As identified earlier in this Review Report, this facility has insignificant emissions units (IEUs) that include 

categorically insignificant activities and aggregate insignificant emissions, as defined in OAR 340-200-0020. 

EU4 and EU7 are considered to be part of the facility’s IEUs. For the most part, the standards that apply to 

IEUs are for opacity (20% limit) and particulate matter (0.1 gr/dscf limit). DEQ does not consider it likely that 

IEUs could exceed an applicable emissions limit or standard because IEUs are generally equipment or 

activities that do not have any emission controls (e.g., small natural gas fired space heaters) and do not 

typically have visible emissions. Since there are no controls, no visible emissions, and the emissions are less 

than one ton per year, DEQ does not believe monitoring, recordkeeping, or reporting is necessary for assuring 

compliance with the standards. 
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 29 of 31

PLANT SITE EMISSION LIMITS

61. Provided below is a summary of the baseline emissions rate, netting basis, plant site emission limits, and 

emissions capacity.

Pollutant

Baseline 

Emission 

Rate 

(tons/yr)

Netting Basis

Plant Site Emission Limit (PSEL)

Capacity 

(tons/yr)

Previous 

PSEL 

(tons/yr)

Proposed 

PSEL 

(tons/yr)

PSEL 

Increase 

(tons/yr)

Previous 

(tons/yr)

Proposed 

(tons/yr)

PM 0 0 198 0 198 198 198

PM10 0 0 198 0 198 198 198

PM2.5 n/a 0 198 0 198 198 198

SO2 0 0 0 0 39 39 36

NOx 0 0 227 0 227 227 227

CO 0 0 643 0 643 643 643

VOC 0 0 212 0 212 212 212

GHG (CO2e) 0 0 2,730,000 0 2,730,000 2,730,000 2,730,000

H2SO4 0 0 19 0 19 19 19

61.a. The proposed Netting Basis and PSELs including the following for aggregate insignificant emissions:

61.a.i. 1 ton per year for PM, PM10, PM2.5, SO2, NOx, CO and VOC;

61.a.ii. 0.7 ton per year for H2SO4 (and rounded off to the nearest digit); and

61.a.iii. 2,756 tons per year for GHG and rounded off to the nearest thousand.

61.b. Baseline emission rate:

61.b.i. The baseline years for all pollutants listed except GHG and PM2.5 are 1977/78 or an earlier 

year. This facility did not exist during these baseline years, so the baseline emission rate for 

those pollutants is zero (0).

61.b.ii. The baseline year for GHG is a 12-month period in the years 2000 through 2010. This 

facility did not exist during these baseline years, so the baseline emission rate for GHG is 

zero (0).

61.b.iii. There is no baseline year or baseline emission rate for PM2.5 pursuant to DEQ’s rules.

61.c. Since this is a newly permitted facility, it does not have a previous netting basis.

61.d. This facility is subject to NSR/PSD for all pollutants listed in paragraph 61 except SO2. In accordance 

with OAR 340-200-0020(76), definition of netting basis, the proposed netting basis for each pollutant 

except SO2 is the same as the requested PSEL.

61.e. The proposed PSEL for each pollutant except SO2 is set at the potential to emit of the facility, as 

requested by the applicant. PSELs are detailed in the emissions detail sheets.

61.f. This facility is not subject to NSR/PSD for SO2. In accordance with OAR 340-200-0020(76), 

definition of netting basis, the netting basis for SO2 is zero (0). The PSEL for SO2 has been set at the 

generic level for SO2 of 39 tons per year.
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 30 of 31

62. This facility is subject to the netting basis “reset” provision in the definition of netting basis, OAR 340-200-

0020(76)(g), which states: “For permits issued after May 1, 2011 under New Source Review regulations in 

OAR 340 division 224, and where the netting basis initially equaled the potential to emit for a new or modified 

source, the netting basis will be reduced in accordance with the definition of actual emissions. Notwithstanding 

OAR 340-222-0041(2), this adjustment does not require a reduction in the PSEL.” The relevant portions of the 

definition of actual emissions, OAR 340-200-0020(3)(b) and (c), provide for the following:

62.a. Except as provided in paragraph 62.c, ten years from the date this permit is issued, or an earlier time if 

requested by the source in a permit application involving public notice, DEQ will reset actual 

emissions to equal the highest actual emission rate during any consecutive 12-month period during the 

ten year period or any shorter period if requested by the source. 

62.b. Any emission reductions achieved due to enforceable permit conditions based on OAR 340-226-0110 

and 0120 (highest and best practicable treatment and control) are not included in the reset calculation. 

62.c. DEQ may extend the date of resetting by five additional years upon satisfactory demonstration by the 

source that construction is ongoing or normal operation has not yet been achieved.

SIGNIFICANT EMISSION RATE

63. The proposed PSEL is greater than the previous netting basis as shown below, and this facility subject to the 

provisions of Prevention of Significant Deterioration and New Source Review in OAR 340 Division 224, as 

discussed elsewhere in this report, for all listed pollutants except SO2. The proposed PSEL for SO2 is less than 

the significant emission rate (SER) and this PSEL can be approved without meeting any additional 

requirements.

Pollutant SER

Requested increase over 

previous netting basis

Increase due to utilizing 

capacity that existed in the 

baseline period

Increase due to physical 

changes or changes in the 

method of operation

PM 25 198 0 198

PM10 15/5*

198 0 198

PM2.5 10 198 0 198

SO2 40 39 0 39

NOx 40 227 0 227

CO 100 643 0 643

VOC 40 212 0 212

GHG (CO2e) 75,000 2,730,000 0 2,730,000

H2SO4 7 19 0 19

*For PM10, the first value is for sources located anywhere in the state other than the maintenance portion of the 

Medford-Ashland AQMA. In the Medford-Ashland Maintenance Area, the SER for PM10 is 5 tons/yr. 
Review Report/Permit No.: 26-0235-ST-01

Final Application number: 027060

Page 31 of 31

HAZARDOUS AIR POLLUTANTS

64. The applicant has estimated the maximum Hazardous Air Pollutant (HAP) emissions to be 11.5 tons per year 

for the combination of all HAPs emitted, with the largest single HAP being formaldehyde at 7 tons per year. 

Based on these emissions estimates, this facility is not a major source of HAPs. The ten HAPs with the largest 

emissions estimates are listed below, along with the primary source of the emissions.

HAP tons per year Primary source

Formaldehyde 6.97 Combustion turbines, while burning natural gas

Hexane 1.94 Combustion turbines, while burning natural gas

Toluene 1.23 Combustion turbines, while burning natural gas

Xylenes 0.602 Combustion turbines, while burning natural gas

Acetaldehye 0.376 Combustion turbines, while burning natural gas

Benzene 0.157 Combustion turbines, while burning natural gas

Acrolein 0.0602 Combustion turbines, while burning natural gas

PAH 0.0508 Combustion turbines, while burning ULSD

Naphthalene 0.0402 Combustion turbines, while burning ULSD

1,3-Butadiene 0.0161 Combustion turbines, while burning ULSD

COMPLIANCE HISTORY

65. This is a new facility and there is no compliance history.

SOURCE TEST RESULTS

66. This is a new facility and no source tests have been completed.

PUBLIC NOTICE

67. This permit was placed on public notice until 5:00 pm, October 14, 2013. DEQ held a public hearing on the 

draft permit on October 3. After the comment period and hearing, DEQ reviewed the comments and modified 

the permit as discussed in the response to comments. The permit was issued on March 5, 2014.

Attachments: Air Quality Analysis Review
State of Oregon

Department of Environmental Quality Memorandum

____________________________________________________________________________________________

Date: 2 August 2013

To: George Davis

From: Svetlana Lazarev

Through: Phil Allen

Subject: Troutdale Energy Center

1. Background

Troutdale Energy Center, LLC (TEC) submitted an ACDP application to construct and operate a natural 

gas-fired power plant at the Port of Portland-owned Troutdale Reynolds Industrial Park (TRIP), located 

in the City of Troutdale, Oregon. The TRIP is a long-vacant brownfield site with a history of heavy 

industrial use as an aluminum reduction plant. The Applicant’s proposal is to locate a power plant, to be 

called the Troutdale Energy Center (TEC, Facility, or the proposed project), at the TRIP. The air quality 

analysis was performed by CH2MHILL.

The proposed Facility will have an expected nominal output of 653 megawatts (MW), of which 451 MW 

will come from a combined-cycle plant and 202 MW from a simple-cycle plant.

The combined-cycle plant will consist of a turbine, with a heat-recovery steam generator (HRSG) 

equipped with the capability of duct firing. Natural gas will be the primary fuel for the combined-cycle

power plant; however, during times of natural gas curtailment, the unit will be able to fire ultra-low sulfur

distillate (ULSD). 

The simple-cycle plant will consist of two turbines. These turbines also will be primarily fueled with 

natural gas and have the capacity to operate on ULSD. 

In addition to the combustion turbines and HRSG, other equipment for the proposed project with air 

emissions will include two small cooling towers, an ULSD-fired emergency fire pump engine, a natural 

gas-fired auxiliary boiler, and a ULSD storage tank.

2. Plant Configuration and Emissions

Plant Configuration. 

The combined-cycle plant will consist of a Mitsubishi M501-GAC turbine, with a heat-recovery steam 

generator (HRSG) equipped with the capability of duct firing. Natural gas will be the primary fuel for the 

combined-cycle power plant; however, during times of natural gas curtailment, the unit will be able to fire 

ultra-low sulfur distillate (ULSD). The combined-cycle plant will not duct fire when burning ULSD.

The simple-cycle plant will consist of two General Electric (GE) LMS 100 turbines. These turbines also 

will be primarily fueled with natural gas and have the capacity to operate on ULSD. Each power block 

will be limited to 720 hours per calendar year of firing ULSD.
Memo to George Davis

2 August 2013

Page 33

In addition to the combustion turbines and HRSG, other equipment for the proposed project with air 

emissions will include two small cooling towers, an ULSD-fired emergency fire pump engine, a natural 

gas-fired auxiliary boiler, and a ULSD storage tank.

Plant operation is assumed to be 8,760 turbine operating hours, with 720 hours designated for ULSD

and 321 hours designated to startup/shutdown emissions.

Plant Operation and Emissions. 

Turbine emissions and stack parameters, such as flow rate and exit temperature, exhibit some variation 

with ambient temperature and operating load. To account for potential variations, emissions were

estimated for a variety of ambient temperatures and partial loads. Based on anticipated demand on the 

combustion turbines and the range of temperatures expected at the project site, loads analyses at 50 

percent, 75 percents, and 100 percent loads for three different temperatures of 0F, 59F, and 108F were 

performed. The worst-case scenario was then used in the Significant Impacts Level (SIL) modeling 

analysis. 

Emissions estimates for the proposed Facility are based on the project’s anticipated use of the a dualfuel combustion turbine operating in combined-cycle mode with supplemental duct firing, two dual-fuel 

combustion turbines operating in simple-cycle mode, a natural gas-fired auxiliary boiler, a ULSD-fueled 

fire pump, cooling tower equipment, and a ULSD fuel storage tank. 

Maximum annual facility wide potential emissions estimates of CO, NOx, PM10, PM2.5, SO2, and VOC 

are shown in Table 1. Annual estimates assume 8,760 turbine operating hours, with 720 hours 

designated for ULSD and 321 hours designated to startup/shutdown emissions.

Table 1. Maximum Potential Emissions Estimates

SO2 emissions were under the Significant Emissions Rate (SER) and no additional analysis was 

required. Facility emissions of CO and VOC were offset by available growth allowances identified in the 

Portland Area Carbon Monoxide and Ozone Maintenance Plans, and a modeling analysis of CO and 

VOC was also not required. 

Since PM10, PM 2.5, and NOx emission levels exceeded the SER, their impacts were evaluated in the 

SIL dispersion modeling analysis. 

The most conservative emissions scenarios were identified in the preliminary analysis. Twenty cases of 

different loads and ambient conditions were studied to determine the combination of emissions and 

Pollutant Total Emissions 

tpy

SER 

tpy

CO 642.0 100

NOx 226.2 100

PM10 197.4 15

PM2.5 197.4 10

SO2 34.6 40

VOC 210.9 40

Table 1 Maximum Potential Emissions Estimates
Memo to George Davis

2 August 2013

Page 34

ambient conditions causing the maximum impacts. The methodology used is described below in the 

Class II Area Analysis. 

Table 2 shows the maximum potential PM10/PM2.5 emissions used in the SIL modeling by equipment 

type and operating scenario. Table 3 shows the maximum potential NOx emissions.

Table 2. Maximum PM10/PM2.5 emissions by equipment type and operating scenario

Emissions Unit Requested 

PM10/PM2.5

Requested 

PM10/PM2.5 

NG

Requested 

PM10/PM2.5 

ULSD

Reguested 

NG

Reguested 

ULSD

Requested 

92% NG, 8% 

ULSD mix

PM10 used in 

modeling 

(annual) 

PM2.5 used in 

modeling (annual) 

includes 

secondary NOx 

and SOx 

PM10/PM2.5 

used in 

modeling (NG, 

24-hour)

PM10/PM2.5 

used in 

modeling 

(ULSD, 24-

hour)

 tpy lb/hr lb/hr g/sec g/sec g/sec gr/sec gr/sec gr/sec gr/sec

Combined Cycle CT 109.3 23.6 42.3 3.0 5.3 3.2 3.15 3.20 1.1 4.6

Simple Cycle CT (2) 87.1 18.2 45.4 2.3 5.7 2.6 2.57 2.61 2.1 4.6

Cooling Tower 0.6 0.2 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Auxilliary Boiler 0.4 0.2 0.4 0.0 0.1 0.0 0.0 0.0 0.0 0.0

Storage Tank - - - - - - - - - -

Fire Pump 0.0 - - - - - - - 0.0 0.0

Total 197.4 42.2 88.3 5.3 11.1 5.8 5.8 5.8 3.2 9.3

 Maximum PM10/PM2.5 emissions by equipment

Short term emissions in grams/second are from the AERMODE input files. NG emissions are from case 

11 for combined cycle operation and case 8 for simple cycle operation. ULSD emissions are from cases 

20 and 18 for combined cycle and simple cycle operation respectively. Annual combined cycle PM10/2.5 

emissions are from case 12. Annual Simple Cycle PM10/2.5 emissions are from case 4.

Load Analysis Scenarios Description: 

Combined Cycle Operation Case 11: NG, 50% load, 59F/60% RH, 1662.10 MMBTU/hr; stack exit 

temperature 175 F, exit velocity 31ft/s;

Combined Cycle Operation Case 20: ULSD, 60% load, 108 F/15% RH, 1425.80MMBTu/hr, stack exit 

T 273 F, exit velocity 37 ft/s;

Simple Cycle Operation Case 8: NG, 59F, 324.17 MMBtu/hr, , 25% load, stack exit T 864 F, exit 

velocity 78 ft/s;

Simple Cycle Operation Case 18: ULSD, 108F, 591 MMBtu/hr, 75% load, stack exit T 840.6 F, exit 

velocity 86ft/s

Combined Cycle Operation Case 12: NG, 50% load, 108 F/15% RH, 1487.9 MMBTU/hr, stack exit 

temperature 176.7F, exit velocity 30 ft/s; 

Simple Cycle Operation Case 4: NG, 100% load, 0F/95% RH, 3484.3 MMBTU/hr, stack exit 

temperature 191F, exit velocity 52 ft/s;
Memo to George Davis

2 August 2013

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Table 3. Maximum NOx emissions by equipment type and operating scenario

Emissions Unit Requested NOx Requested 

NOx NG

Requested 

NOx ULSD

Reguested 

annual 

Requested 

short term 

NG

Reguested 

short term 

ULSD

gr/sec used in 

modeling 

(annual NO2l)

gr/sec used in 

modeling (1-hr 

NO2)

 tpy lb/hr lb/hr gr/sec gr/sec gr/sec NG and ULSD NG aand ULSD

Combined Cycle CT 138.0 25.7 54.7 4.4 3.2 6.9 4.0 2.6

Simple Cycle CT (2) 87.0 17 25.4 2.7 2.1 3.2 2.5 3.1

Cooling Tower - - -

Auxilliary Boiler 2.8 1.39 - 0.1 0.2 0.1 0.2

Storage Tank - - -

Fire Pump 0.2 - - 0.0

Total 228.0 44.1 80.1 7.2 5.6 10.1 6.6 5.8

 Maximum NOx emissions by equipment

Short term Combined Cycle operation NO2 emissions are from Case 6. Short term simple cycle operation 

NO2 emissions are from Case 19. Annual Combined Cycle Operation NO2 emissions are from Case 12, 

annual simple cycle operation NO2 emissions are from Case 4. 

Load Analysis Scenarios Description:

Combined Cycle Operation 1-hr NO2 Case 6: NG, 100% load, 108F/15% RH, 20.45 lb/hr total NOx 

emissions

Simple Cycle Operation: 1-hr NO2 Case 19: ULSD, 50% load0F, 7.6 lbs/hr total NOx emissions

Combined Cycle Operation Annual NO2 Case 12: ULSD, 50% load108F/15% RH, 10.96 lbs/hr total 

NOx emissions

Simple Cycle Operation Annual NO2 case 4: NG, 25% load, 108F, 3lb/hr total NOx

3. Class II Area Analysis: Parameters

Model

The AERMOD model version 12060 with regulatory default options recommended in the EPA Guideline 

on Air Quality Models was used in load analysis and Class II area analysis.

The following supporting pre‐processing programs for AERMOD were used:

BPIP‐Prime (Version 04274)

AERMET (Version 11059)

AERMAP (Version 11103)
Memo to George Davis

2 August 2013

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The combustion turbines and auxiliary equipment were modeled as point sources within AERMOD. 

Building Downwash 

Building influences on stacks were calculated by incorporating the EPA Building Profile Input Program 

with the plume‐rise model‐enhancement algorithm (BPIP‐PRIME). 

Receptor Grids

The first run used a nested Cartesian grid as follows:

- 25‐meter (m) spacing along the fenceline

- 100m spacing from property boundary to 1 km from the fenceline

- 500m spacing from beyond 1 km to5 km from the fenceline

- 1000m spacing from beyond 5 km to 20 km from the fenceline

- 5000m spacing from beyond 20 km to 50 km

The second run using a 100-m receptor grid was centered on the point of maximum impact.

Receptor elevations were calculated by AERMAP Version 11103 using National Elevation Dataset (NED) 

files prepared by the USGS. 

All receptors and source locations will be expressed in the Universal Transverse Mercator North 

American Datum1983 (NAD83), Zone 10 coordinate system.

Meteorology

Five years of data (2006-2010) collected at the Troutdale Airport (AWS #726985) were used in this 

analysis. The AERMET Version 11059 was used to prepare meteorological data for use in AERMODE. 

Available one minute ASOS data preprocessed with AERMINUTE (Version 11325) was supplemented 

into the AERMET dataset. 

Surface: surface meteorological data from the National Weather Service at the Salem upper air station 

(WBAN#24232) has been used in AERMET. 

Upper Air: twice-daily soundings data for Salem upper air station (WBAN#24232) were obtained from the 

National Climatic Data Center.

Background Concentrations

Three consecutive years (2008-2010) of ambient PM10, PM2.5, and NO2 concentrations from the SE 

Lafayette monitoring station in Portland, OR (Site ID 410510080, 5824 SE Lafayette St.) were used to 

calculate the Background Concentrations. 

However, for receptors in Washington, PM2.5 representative background was calculated from the annual 

average and maximum 24-hour PM 2.5 ambient concentrations at the Camas monitor (Site ID 

530110020, 616 NE 4th Ave. Camas, WA). The monitor was operational from April 2001 to May 2002.
Memo to George Davis

2 August 2013

Page 37

4. Class II Area Analysis: SIL Modeling Results 

The SIL analysis of PM 10, PM 2.5, and NOx impacts was performed using the worst case load 

identified in the combustion turbines load analysis. The modeled concentrations of each pollutant 

were compared to the SIL. The comparison showed impacts of annual NO2 were not significant and 

no additional modeling to demonstrate compliance with NAAQS or Class II increment was required. 

However, PM10 and PM 2.5 impacts were greater than their respective SILs and a refined modeling 

analysis was performed to demonstrate compliance with NAAQS and PSD increment. 

The results of the SIL Modeling analysis are shown in Table 4

Table 4. Class II SIL Modeling Results

Pollutant Averaging Period Modeled Concentration SIL 

ug/m3 ug/m3

PM2.5 24-hr 5.54 1.2

PM2.5 annual 0.46 0.3

PM10 24-hr 7.05 1

PM10 annual 0.45 0.2

NO2 1-hr 36.59 7.5

NO2 annual 0.45 1

 Class II SIL Modeling Results

For annual and 24-hr PM10, annual PM2.5, and annual NO2, the modeled concentration is the highest of the 5-year 

averages of the maximum modeled concentration predicted each year. For 1-hr NO2, the average of the 5-year 

averages of the maximum modeled concentration predicted each year for all receptors is used as modeled 

concentration in this table. An ambient ratio of 0.75 used to convert annual NOx concentrations to NO2

concentrations. For 1-hr NO2 modeling, NOx emissions were converted to NO2 emissions using the EPA NO2/NOx 

ratio of 0.8.

For 24-hr PM 2.5, the modeled concentration is the average of the 5-year averages of the maximum modeled 

concentration predicted each year.

5. Class II Area Analysis: PM2.5 and PM10 NAAQS and PSD Increments Analysis

A competing source analysis was used to assess impacts relative to the NAAQS and PSD increments. The NAAQS 

analysis included impacts from TEC, competing sources, and background concentrations. The Increment analysis 

included emissions from TEC and increment consuming competing sources. Modeled concentrations were predicted 

under the worst case scenarios described in the Emissions section of this review. The results of PM10 and PM2.5 

modeled concentrations comparison to NAAQS are shown in Table 5.
Memo to George Davis

2 August 2013

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Table 5. NAAQS Modeling Results

Pollutant Averaging Period Modeled Concentration Background Concentration Total Concentration NAAQS

ug/m3 ug/m3 ug/m3 ug/m3

PM2.5 24-hour 14 16.8 30.8 35

PM2.5 annual 1.5 8.36 9.83 15

PM10 24-hour 14.1 41 55.1 150

 NAAQS Modeling Results

As shown in the table, the 24-hr PM2.5 modeled concentration is the average of the 5-year averages of 

the maximum modeled concentration predicted each year. The annual PM 2.5 modeled concentration is 

the highest of the 5-year averages of the maximum modeled concentration predicted each year. The 

24-hr PM10 modeled concentration is the highest 2nd high of the 5-year averages of the 2nd high 

modeled concentration predicted each year. 

Since the PM2.5 annual modeled concentration used in NAAQS comparison was predicted at a Washington receptor, 

the background concentration from Camas monitoring site was used in calculating the total concentration. The 

PM2.5 24-hour modeled concentration used in this comparison was predicted at an Oregon receptor, therefore the 

background concentration from SE Lafayette monitoring site was used to calculate the total concentration. 

The results of PSD increment analysis are shown in Table 6.

Table 6. Class II PSD Increments Comparison

Pollutant Averaging Period Modeled Concentration Class II PSD Increment 

ug/m3 ug/m3

PM2.5 24-hour 7.6 9

PM2.5 annual 1.5 4

PM10 24-hour 14.1 30

PM10 annual 2.6 17

 PSD Increment Comparison Results

The 24-hr PM2.5 modeled concentration used in this table is the average over five years of the 8th highest (98%-tile) 

modeled concentration predicted each year.

6. Class II Area Analysis: One-hour NO2 NAAQS Analysis

The NO2 competing source analysis showed impacts greater than the 1-hr NO2 NAAQS at five receptors. To assess 

the TEC contribution to these exceedances, its impacts at each of the five receptors were evaluated. For each 

receptor with an exceedance of the 1-hour NO2 NAAQS (the five year average of the 98%-tile), the TEC 

contribution was determined to be less than the interim 1-hr NO2 SIL of 7.5 ug/m3.

The results of this comparison are in Table 7.
Memo to George Davis

2 August 2013

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Table 7. Facility contributions to 1-hr NO2 Modeled Exceedances

Facility Contribution SIL 

UTM X UTM Y ug/m3 ug/m3

544500 5048500 0.02

543000 5049000 0.01

545500 5049000 0.11

543500 5050000 0.01

545500 5050000 6.6 7.5

Receptor location

Facility contributions to 1-hr NO2 Modeled Exceedances

7. Class I Area Analysis

A dispersion modeling analysis was conducted to demonstrate compliance with Class I Area Increment and Air 

Quality Related Values (AQRVs) at the Class I areas within 300 km of the proposed TEC project site. Class I 

areas within the 300 km radius of the project site are summarized in Table 8. 

Table 8. Summary of Class I areas within 300 km radius

Class I Area Distance from TEC For Q = 976 tpy

km Q/D

Mt Hood Wilderness 44.8 21.8

Mt. Adams Wilderness 88.86 11

Mt. Jefferson Wilderness 94.78 10.3

Goat Rocks Wilderness 117.08 8.3

Mt. Rainier National Park 135.96 7.2

Mt. Washington Wilderness 136.79 7.1

Three Sisters Wilderness 150.74 6.5

Alpine Lakes Wilderness 216.48 4.5

Diamond Peak Wilderness 219.19 4.5

Olympic National Park 226.41 4.3

Crater Lake National Park 265.76 3.7

Glacier Peak Wilderness 280.42 3.5

Summary of Class I areas within 300 km radius

8. Increment Analysis

Model 

CALPUFF Version 5.8 was used to model the annual NOx, PM10, and PM2.5, and 24-hour PM10 and PM2.5 

impacts from all TEC sources in Class I areas.
Memo to George Davis

2 August 2013

Page 40

CALMET was used to generate wind field and boundary layer parameters. Digital Elevation Model (DEM) and 

Land Use/Land Cover data and Weather Research and Forecasting (WRF) data at 4km resolution were used to 

develop CALMET input files based on EPA 2009 guidance.

BPIP was used to calculate building downwash.

Receptors: Discrete receptors from the National Park Service Class I receptors database. 

8.1 Class I Area Analysis: SIL and PSD Increments Modeling Results 

The modeled concentrations were compared to Class I SIL for each pollutant. The maximum predicted impacts 

of the modeled pollutants are shown in Table 9.

Table 9. Class I SIL Modeling Results

Class I Area PM10 24-hr PM10 annual PM2.5 24-hr PM2.5 annual NO2 annual

ug/m3 ug/m3 ug/m3 ug/m3 ug/m3 

SIL 0.3 0.2 0.007 0.06 0.1

Mt Hood Wilderness 0.58 0.021 0.58 0.021 9.11E-09

Mt. Adams Wilderness 0.08 0.005 0.08 0.005 2.54E-09

Mt. Jefferson Wilderness 0.14 0.008 0.14 0.008 3.04E-09

Goat Rocks Wilderness 0.06 0.004 0.06 0.004 1.76E-09

Mt. Rainier National Park 0.05 0.003 0.05 0.003 1.57E-09

Mt. Washington Wilderness 0.1 0.005 0.1 0.005 1.57E-09

Three Sisters Wilderness 0.08 0.004 0.08 0.004 1.27E-09

Alpine Lakes Wilderness 0.02 0.001 0.02 0.001 7.00E-10

Diamond Peak Wilderness 0.04 0.002 0.04 0.002 6.34E-10

Olympic National Park 0.03 0.000818 0.03 0.000818 3.32E-10

Crater Lake National Park 0.03 0.001 0.03 0.001 3.46E-10

Glacier Peak Wilderness 0.02 0.000883 0.02 0.000883 4.24E-10

Class I SIL Modeling Results

The 24-hour PM10 and 24-hour PM2.5 predicted impacts exceeded their respective SILs at the Mt. Hood 

Wilderness area. A 24-hour PM10 competing sources impact analysis was completed to demonstrate compliance 

with Class I PSD Increment. The competing sources analysis included all large PM10 increment consuming 

sources within the range of influence for the Mt. Hood Wilderness. 

A 24-hour PM2.5 competing sources increment analysis was not required since there have been no PM2.5 PSD 

sources constructed within the range of influence for the Mt. Hood Wilderness since the 2011 PM2.5 baseline. 

 

 The results of Class I PSD increment analysis are shown in Table 10.

Table 10. Class I PSD Increments Competing Sources Results

Class I Area Pollutant Averaging Period Cumulative Concentration Class I Increment

ug/m3 ug/m3

Mt. Hood Wildeness PM10 24-hour 0.73 8

Class I PSD Increments Competing Sources Results
Memo to George Davis

2 August 2013

Page 41

9. Class I AQRV Analysis

For Air Quality Related Values (AQRV) analysis, the Federal Land Managers (FLM)

required the use of the Mesoscale Model Interface Formatter (MMIF) for pre-processing of the WRF 

meteorological data for use in Calpuff. 

Model

MMIF – Beta

CALPUFF - version 5.8, level 070623

CALPOST - version 5.6394, level 070622

CALPOST – version 6.221, level 080724 with method 8 processing option

Based on the Q/D calculation, the Federal Land Managers determined that only those Class I areas with a 

Q/D greater than 10 required modeling for AQRVs. Only three Class I areas met this criteria, they are the 

Mount Hood, Mount Adams, and Mount Jefferson Wilderness Areas.

Receptors:

Discrete receptors for these three Class I areas are from the National Park Service Class I receptors 

database. 

Ozone and Ammonia 

Ozone data used in this analysis is from EPA AQS station (ID 41-051-0080); the station is 17.6 km away 

from the project site. The data were collected between years 2006 and 2010. The average monthly ozone 

concentrations varied between 13 and 28 ppb. 

Ammonia data was collected at three stations in the Columbia River Gorge. The FLM provided 2006 

weekly average concentrations for this analysis. At the direction of FLMs, the maximum average weekly 

data point for each month was used as a background concentration. 

Deposition 

Atmospheric deposition at the three Class I areas was assessed. For each of those areas, the total nitrogen 

deposition analysis was conducted using the CALPUFF. The modeled total nitrogen deposition potentially 

resulting from the facility is below the FLM developed Deposition Analysis Threshold (DAT) of 0.005 

kg/ha/yr. The results are shown in Table 11. 
Memo to George Davis

2 August 2013

Page 42

Table 11. Nitrogen Deposition Modeling Results

Class I Area Total Nitrogen Deposition

kg/ha/yr

Mt. Hood 0.0039

Mt. Adams 0.0018

Mt. Jefferson 0.0009

Class I DAT 0.005

Nitrogen Deposition Modeling Results

Visibility

The Facility’s impacts on visibility at the three Class I areas were assessed using the CALPUFF. The 

results of the visibility analysis in Table 13 demonstrate that the visibility impacts are lower than the Class 

I visibility guideline threshold of a 5% increase of extinction.

At the request of the US Forest Service FLM, the ambient background concentrations of light attenuating 

pollutants for the Class I areas included in this analysis are based on the 20 percent best day visibility 

conditions. The values associated with these conditions are presented in Table 12. 

Rayleigh scattering is 10 inverse megameters for Mount Hood and Mount Adams Wilderness areas and 11 

inverse megameters for Mount Jefferson Wilderness area.

Table 12. Background Concentrations of Light Attenuating Pollutants

 Background Concentrations of Light Attenuating Pollutants

Aerosol Component Mt. Hood Mt. Adams Mt. Jefferson

concentration concentration concentration 

ug/m3 ug/m3 ug/m3

Ammonium Sulfate 0.02 0.02 0.02

Ammonium Nitrate 0.02 0.01 0.02

Organic Matter 0.06 0.06 0.08

Elemental Carbon 0 0 0

Soil 0.05 0.04 0.03

Coarse Mass 0.15 0.21 0.31

Sea Salt 0.01 0.01 0.01

The Modeled change in light extinction potentially attributable to TEC impacts is presented in Table 13. The 

impact at all three Class I area analyzed are predicted to be within the FLAG 2010 visibility guideline threshold 

of 5% change in light extinction as compared to background.
Memo to George Davis

2 August 2013

Page 43

Table 13. Far-field Visibility Analysis Results

Visibility Impacts: Percent Change in Light Extinction

Class I Area Change in light extinction

%

Mt. Hood 4

Mt. Adams 1.5

Mt. Jefferson 1.6

Class I Visibility Treshold 5

Near-Field Visibility

A near field visibility analysis of the TEC impacts on the Mount Hood Wilderness area was performed 

using the EPA-approved VISCREEN model (version 1.01). The analysis demonstrates near-field visibility 

impacts from TEC to be in compliance with the screening criteria. The results of the near-field visibility 

analysis presented in Table 14 demonstrate that the near-field visibility impacts from TEC are in 

compliance with the screening criteria.

Table 14. Near-Field Visibility Analysis Results

Class I Area Nearest BorderFurthest Border

km km Sky 10 Sky 140 terrain 10 terrain 140 Sky 10 Sky 140 terrain 10terrain 140

Mt. Hood Wilderness 44 66 1.259 0.42 1.512 0.22 0.016 -0.013 0.017 0.008

Screening Criteria 2 2 2 2 0.05 0.05 0.05 0.05

Delta E Contrast

Near-Field Visibility Analysis Results
Memo to George Davis

2 August 2013

Page 44

10. Columbia River Gorge AQRV Analysis

An analysis of AQRV impacts in the Columbia River Gorge National Scenic Area (CRGNSA) was 

requested in accordance with OAR 340-225-0070(3)(a), which reads “The Department also 

encourages the owner or operator to demonstrate that these same emission increases or 

decreases will not cause or contribute to significant impairment of visibility on the Columbia River 

Gorge National Scenic Area...” These voluntary analyses are considered to be made for 

informational purposes.

Since there are no modeling criteria or thresholds designated for the CRGNSA, Class I Area 

thresholds are used for comparison, keeping in mind that the CRGNSA is a multiuse area, 

including commercial and transportation activities, and not a pristine wilderness area.

The TEC AQRV analysis went through a number of iterations with input from DEQ and the U.S. 

Forest Service (USFS), which is the FLM of the area in which the CRGNSA is located. This 

CRGNSA analysis was provided as a separate report to DEQ on April 2013 as part of the air 

quality analysis for the TEC. After the final CRGNSA analysis was completed, the USFS 

performed its own analysis and these results and comments were provided by the USFS Scenic 

Area manager in a letter, with technical attachment, to DEQ in June 2013. Finally, in response to 

the USFS comments, TEC provided additional information and comments in a letter in July 2013.

As might be expected there are some differences in the results, in part because of the metrics 

used in the analysis. However, the results are consistent and are summarized below for the three 

AQRVs that were the focus of the analysis: haze visibility, plume visibility, and nitrogen 

deposition.

Haze Visibility.

The values shown in Table 15 are a compilation from the TEC CRGNSA Report, the USFS 

comments, and the TEC letter of July. 

Table 15. CRGNSA Regional Haze Analysis.

2009 2010 2011 2009 2010 2011 2009 2010 2011

Max delta DV 2.928 2.377 2.006 4.436 3.652 3.204

98th%tile delta DV 3.924 2.259 2.379 132 78 99

90th%tile delta DV 1.373 0.926 1.040 2.252 1.526 1.683

Annual Avg Background 20% Best Days Background No. Days delta DV > 1.0

Regional Haze Analysis

While the 98th %-tile delta DV is the value for comparison against the Class I Area Visibility 

thresholds of 0.5 and 1.0 for determining the level of visibility impairment, the 90th %-tile delta DV 

may be a more appropriate value for the Scenic Area. In addition as shown in the TEC Report, 

all values of delta DV greater than 1.0 at the 90th %-tile occur within 16 km of the proposed plant 

and within about 15 km from the west boundary of the Scenic Area. Typically, the haze visibility 

analysis is done at distances beyond 50 km. Visibility analyses at distances less than 50 km 

assess plume visibility, and use different models.

Plume Visibility.

A plume visibility analysis was conducted using the EPA PLUVUE II model (Version 96170, Level 1.0). 

This analysis evaluated the following parameters and thresholds: reduction of visual range (greater than 
Memo to George Davis

2 August 2013

Page 45

5%), plume contrast (greater than 0.02), blue-red ratio (less than 0.9 or greater than 1.1), and delta E. Of 

these, EPA considers delta E as the best indicator of plume perceptibility. Note that the Class I area 

threshold for delta E is 1.0 for a PLUVUE II analysis. TEC used a less conservative value of 2.0 as a delta 

E threshold for the Scenic Area.

The analysis considered three plume directions based on wind directions of 250, 270, and 280 degrees, 

blowing from the plant into the Gorge. Hypothetical observers were placed at five locations in the Gorge, 

with the furthest observer located at 20 km from the facility. Plume visibility was assessed for each 

observer at six points on each of the three plumes. Modeled data for the observer at position 3, 12 km from 

the plant, was chosen to be representative of visibility conditions in the Gorge because of its proximity to 

recreation areas including Crown Point, and the results from this observer location show the highest 

impacts of delta E. 

A summary of the results from the TEC analysis for Observer 3 of the six points along the centerlines of 

the three plumes is shown in Table 16. Plume visibility was evaluated against four different backgrounds: 

Sky, Gray, Black, and White. With the exception of Visual Range using Sky as background, only the 

model results using a gray background are shown in the Table. A gray background is probably the most 

likely shade in the Scenic Area, especially during the early morning and early evening hours.

The frequencies shown in the Table are the number of hours that the criterion was exceeded for that 

parameter, and are not correlated with the maximum values for each wind direction. For example, the 

frequency that the maximum visual range was reduced by more than 5% along the 280 degree wind 

direction plume was 14 hours. The maximum reduction of 33.4% at the distance of 1 km only occurred for 

1 hour.

Table 16. CRGNSA Plume Visibility Analysis

Wind

Parameter Direction Frequency 1 km 2 km 4 km 8 km 12 km 16 km Criterion

260 2 5.6 4.6 3.2 1.6 0.9 1.5

270 6 13.3 11.0 7.6 3.2 1.0 3.0

280 14 33.4 27.5 18.9 7.9 1.3 6.1

260 0 1.0/0.9 1.0/0.9 1.0/0.9 1.0/1.0 1.0/1.0 1.0/1.0

270 4 1.0/0.9 1.0/0.9 1.0/0.9 1.0/0.9 1.0/1.0 1.0/0.9

280 8 1.0/0.8 1.0/0.8 1.0/0.8 1.0/0.9 1.0/0.9 1.0/0.8

260 4 0.05 0.04 0.02 0.01 0.01 0.03

270 11 0.09 0.08 0.05 0.03 0.01 0.08

280 31 0.17 0.15 0.11 0.06 0.09 0.33

260 0 2.4 2.0 1.5 0.7 0.4 1.1

270 4 4.8 4.3 3.3 1.6 0.4 3.3

280 22 8.4 8.0 7.0 4.5 4.2 10.6

Max Plume 

Perceptiblity delta E 

(Gray Background)

2.0

Max % reduction in 

Visual Range (Sky 

Background)

Max/Min Blue-Red 

Ratio (Gray 

Background)

5%

1.1/0.9

Max Plume Contrast 

(Gray Background) 0.02

Plume Visibility Analysis for Observer 3

Distance Plume Has Traveled

Using the delta E parameter as the best indicator of plume perceptibility, the PLUVUE results show that 

within a distance of about 20 km from the western boundary of the Scenic Area the threshold of 2.0 is 

exceeded about 26 daylight hours during a year. 

In its critique of the TEC analysis, the USFS looked more closely at the joint frequency distribution of wind 

direction, wind speed, and air stability classification. For comparison, the USFS used a delta E threshold 

value of 1.0, which is the value recommended by FLAG guidance for Class I areas. Also, the analysis by 

the USFS showed higher delta Es that could occur in the early morning and early evening hours. However, 

as pointed out in the TEC July comment letter, if the model results during E and F stability conditions 

(considered to be present only during night time) are removed from the early morning and early evening 

periods, the maximum delta Es are lower or similar to those shown in Table 16. As a result, although the 
Memo to George Davis

2 August 2013

Page 46

USFS re-examined the meteorological data and PLUVUE parameters in greater detail, the model results 

show consistency, within a range, with those reported by TEC.

Nitrogen Deposition.

As part of the deposition analysis, TEC derived a CRGNSA-specific DAT, following the methodology 

used by the FLMs to develop the national generic DATs for Class I areas. The DAT is used to determine 

the significance of deposition from a facility; deposition less than the DAT is considered not significant and 

no additional analysis is required. The nitrogen DAT for western states is 0.005 N kg/ha/yr. The 

CRGNSA-specific DAT calculated in the TEC report is 0.04 N kg/ha/yr.

The TEC analysis showed that impacts greater than 0.04 N kg/ha/yr from the proposed plant were limited 

to an area within about 2 km of the western end of the Scenic Area. This area is currently heavily used, and 

includes the Sandy River Delta Park open to equestrian activities, off-leash dogs, biking, hiking and other 

recreational uses. The USFS is currently engaged in the Sandy River Basin Aquatic Habitat Restoration 

Strategy and expressed concerns about any additional nitrogen deposition especially as it might affect fish 

habitat and riparian restoration. However, as noted by the USFS this is a mixed use area with substantial 

activity and the relatively low levels of nitrogen deposition may not adversely affect restoration efforts.

The Columbia River Gorge Air Study and Strategy of 2011 states that:

the most effective approach to mitigate and improve haze conditions in the Gorge is 

through implementation of the federally-mandated Regional Haze Program....

The goal for visibility in the Gorge is continued improvement, the same approach 

used in the federal Regional Haze Program. Due to the mix of urban and rural 

activities in the Gorge, longer term visibility improvement cannot be expected to 

reach “natural conditions” as is the case for pristine wilderness areas and national 

parks. However, visibility improvement in the Gorge can be expected to mirror the 

visibility improvement in Mt. Hood and Mt. Adams that will be achieved by emission 

reduction strategies adopted through the regional haze plans.

The strategy incorporates three key elements: 1) haze visibility conditions (and by extension all AQRVs) in 

the Scenic Area will be improved (managed) through the Federal Regional Haze Program, 2) visibility 

improvements will be over the long term in the timeframe of the Haze Program with goals that extend to 

2064, and 3) because of its mixed use the Scenic Area is not expected to reach the “natural conditions" of 

pristine areas.

As noted above, in evaluating the significance of visibility and deposition impacts, the TEC analysis used 

Class I Area and modified Class I Area thresholds. For example, in the haze analysis, the 90th %tile delta 

DV was used for comparison against annual background with a target threshold of 1.0, in lieu of the 98th

%tile with a threshold of 0.5 DV. In the plume visibility analysis, the target threshold for delta E used in 

the TEC analysis was 2.0 instead of the Class I value of 1.0. For the nitrogen deposition analysis, the DAT 

for the Scenic Area was recalculated using the FLM Class I methodology for a value of 0.04 kg/ha/yr, in 

place of the generic Class I Area DAT of 0.005 kg/ha/yr. This approach is reasonable, and follows the 

guidance in the Gorge Strategy document that states:”There is no scientific justification for selecting one 

air quality threshold over another as the ‘correct’ goal for the Gorge” (p. 6).

The results as presented in the TEC CRGSNA Evaluation show visibility and deposition impacts that, in 

some cases, are greater than the Class I Area thresholds. However, the level of these impacts appears 

consistent with the goals of the Gorge Air Strategy document that “visibility improvement cannot be 

expected to reach ‘natural conditions’ as is the case for pristine wilderness areas.” In addition, these results 

should be set against the concurrent improvement in visibility in the Scenic Area that is the result of the 

Best Available Retrofit Technology (BART) process that is part of the Regional Haze Program. BART has 
Memo to George Davis

2 August 2013

Page 47

required significant emissions reductions from two coal-fired power plants (PGE-Boardman in Oregon and 

the Centralia plant in 

Washington). These reductions will result in long term visibility improvements in the Scenic Area and in 

the two Class I areas that flank it.

11. Conclusions 

The review of the air quality analysis of TEC, using the emission rates, stack parameters, unit locations, 

and operating scenarios as provided in the application, shows that all projected impacts comply with 

NAAQS and Class II/ Class I Increment Analyses requirements. In addition, the projected impacts in the 

CRGNSA, in conjunction with the Regional Haze Program, are consistent with the goals of the Gorge Air 

Strategy.

The air quality analysis is approved as submitted. The emission rates as regulated in the permit should be 

no greater than the levels used in this analysis.
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 1 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

The draft permit for the Troutdale Energy Center was placed on public notice from September 4, 2013, 

through October 14, 2013. DEQ held a public hearing on October 3, 2013. A total of 181 individuals and 

organizations submitted comments during the comment period.

Public involvement is an important part of the permit issuance process, and DEQ thanks everyone who 

commented for their involvement in the process and for their time and effort.

The comments are organized into six sections in this document, followed by DEQ’s response to the 

comments. The individuals or organizations that submitted the comments are listed in the appropriate 

section.

DEQ issued the proposed permit to Troutdale Energy Center on March 5, 2014. DEQ made the following 

changes to the permit in response to comments:

 Condition 30 was revised to allow use of Ultra Low Sulfur Diesel (ULSD) for maintenance and 

testing, and to otherwise limit usage in all turbines to periods of curtailment. A definition of 

curtailment was also added. See response to comments beginning on page 12.

 Condition 31 was revised to match the monitoring requirements to the revisions to condition 30.

 Condition 44 was revised to refer to 40 CFR Part 60 Subpart KKKK or TTTT, whichever is 

applicable, instead of Subpart TTTT, and to be applicable to all turbines if the final rule affects all 

turbines. See response to comments beginning on page 21.

 Conditions 50 and 51 were revised to increase the amount of emissions testing of the turbines for 

VOC and PM. See response to comments beginning on page 22.

In addition, the following correction was made:

In condition 1 the word “construct” was replaced with “construct and operate”. This permit was intended 

to allow both construction and operation of the facility, but DEQ inadvertently omitted the words “and 

operate” from condition 1 in the draft permit.

Other minor typographical corrections were made when found. Such corrections did not change the 

requirements of the permit.

Contents

Comments by 177 individuals .......................................................................................................................................2

Comments by Darryl Usher...........................................................................................................................................9

Comments by Paul Wilcox ............................................................................................................................................9

Comments by Allen Johnson, Interlachen Inc. ............................................................................................................10

Comments by NEDC, Friends of the Columbia Gorge and Columbia Riverkeeper....................................................12

Comments by Richard Till, Friends of the Columbia Gorge .......................................................................................25
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 2 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Comments by 177 individuals

Commenters:

Submitted by 177 commenters who are listed beginning on page 3.

Summary of comments:

Deny the Troutdale Energy Center.

The facility is in a bad location near the Columbia River Gorge National Scenic Area would harm the 

Columbia River Gorge.

The facility would release air pollution directly into the Columbia River Gorge, which is already suffering 

from poor air quality

The facility would undermine the purposes of the National Scenic Area Act by harming views from 

numerous key viewing areas.

The facility would harm businesses in the Gorge.

Adopt findings that the facility would cause significant adverse impacts to protected areas and recreation 

sites and that energy from the facility is not needed.

Response:

DEQ does not have the authority to deny permits without legal cause, such as inability to comply with the 

applicable permitting requirements. Troutdale Energy Center has complied with the applicable permitting 

requirements.

DEQ recognizes that the proposed facility is located near the Columbia River Gorge National Scenic 

Area. The applicant has provided information that shows that the facility’s impacts are below levels that 

DEQ considers acceptable for this area. DEQ therefore does not agree that the proposed facility would 

undermine the purposes of the National Scenic Area Act by harming views from numerous key viewing 

areas; would adversely affect recreation sites and resources; would harm businesses in the Gorge; or 

would cause significant adverse impacts to protected areas and recreation sites.

DEQ does not regulate energy production and cannot make findings that the energy from the facility is 

not needed.
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 3 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Ms. Steel

General Delivery

Sandy, OR 97055-9999

Mr. A Michael Dianich

42740 E Larch Mt Rd

Corbett, OR 97019-8774

(503) 695-5385

Ms. Alea Kent

810 Cambridge St

Ashland, OR 97520-1008

Ms. Alex Prentiss

15685 SW 116th Ave

King City, OR 97224-2651

Ms. Alice West

1237 SE 53rd Ave

Portland, OR 97215-2646

Ms. Amy Houchen

2419 SW Richardson St

Portland, OR 97239-2133

Mr. and Mrs John & Polly 

Wood

PO Box

Hood River, OR 97031

note: address incomplete

Ms. Ann Watters

1940 Breyman St NE

Salem, OR 97301-4352

Ms. Aria Jackson

2030 NE Hancock St

Portland, OR 97212-4566

Mr. Arland Swanson

9606 26th Ave NW

Seattle, WA 98117-2515

Dr. Barbara Manildi

3525 Red Cedar Way

Lake Oswego, OR 97035-3523

(503) 635-4878

Mr. Benjamin Ignatowski

PO Box 11807

Portland, OR 97211-0807

(503) 284-6717

Ms. Beth Flake

25 Eugene St

Hood River, OR 97031-2215

Dr. Beth Wilmot

11841 SW 60th Ave

Portland, OR 97219-7003

(503) 449-0035

Ms. Bev Hedin

1720 SW 4th Ave Apt 416

Portland, OR 97201-5533

(909) 241-9930

Mr. Billy Don Robinson

1524 NE Hancock St

Portland, OR 97212-4472

(503) 515-1708

Mr. Bob Welsh

2183 Juneau Ct S

Salem, OR 97302-2221

Ms. Carole Beauclerk

1500 SW Park Ave

Portland, OR 97201-3445

(541) 852-9255

Ms. Carolyn Boatsman

3210 74th Ave SE

Mercer Island, WA 98040-3419

(206) 236-0949

Mr. CharlesBetty BrasherLavis

7709 NE 57th Cir

Vancouver, WA 98662-6239

Ms. Cheryl Wagner

20035 SE 27th Pl

Sammamish, WA 98075-9694

Ms. Colleen Wright

4160 Chapman Way

Lake Oswego, OR 97035-5565

(503) 908-1757

Ms. Corinne McWilliams

6325 NE Lessard Rd

Camas, WA 98607-8948

Ms. Daisy Franzini

PO Box 80248

Portland, OR 97280-1248

Mr. Dan Lamberger

1441 SW Clay St Apt 107

Portland, OR 97201-6044

(503) 274-9956

Mr. Dan Sherwood

1719 SE 35th Ave

Portland, OR 97214-5038

Dr. Daniel Jaffee

4723 NE 14th Ave

Portland, OR 97211-5011

Mr. Dave King

8728 N Edison St

Portland, OR 97203-5316

Mr. David Williams

3049 SW 32nd Ter

Gresham, OR 97080-8482

Ms. Dawn Smallman

1148 SE 50th Ave

Portland, OR 97215-2606

Ms. Debra Rehn

5230 SE 30th Av. Apt. 9

Portland, OR 97202

Dr. Delton Young

7731 21st Ave NE

Seattle, WA 98115-4503

(206) 522-9535

Mr. Derek Gendvil

9030 W Sahara Ave # 360

Las Vegas, NV 89117-5744

Mr. Dermot Noonan

4510 48th Ave NE

Seattle, WA 98105-3824
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 4 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Ms. Diana Moeller

1918 Harris Ave

Richland, WA 99354-2340

Ms. Diane Enochson

9921 N Ivanhoe St

Portland, OR 97203-1419

Ms. Dinda Evans

PO Box 178695

San Diego, CA 92177-8695

Mr. Donald Springer

8321 NE 54th St

Vancouver, WA 98662-6085

Ms. Donna Crane

1576 Beebe Ln

Eugene, OR 97404-2906

(541) 607-7330

Mr. Doug Richardson

2020 SW Main St Unit 801

Portland, OR 97205-1535

(503) 224-0756

Mr. Duff Linde

37713 SE 35th St

Washougal, WA 98671-6775

(360) 798-2804

Mrs. Erika Markel

24495 Butteville Rd NE

Aurora, OR 97002-9666

Ms. Evy Bishop

13932 NE Beech St

Portland, OR 97230-2738

Ms. Frances Hannah

14700 SE 33rd Way Apt 164

Vancouver, WA 98683-9227

Dr. Fredrick Seil

1 Twain Ave

Berkeley, CA 94708-1734

Mr. George Cummings

3816 NE 17th Ave

Portland, OR 97212-1335

(503) 288-2361

Dr. George Pantely

5276 Quinn Dr

Mount Hood Parkdale, OR 

97041-7633

(541) 352-5550

Ms. Gloria McCracken

PO Box 810

Chiloquin, OR 97624-0810

Mr. Gradey Proctor

6003 SE Milwaukie Ave

Portland, OR 97202-5344

Mr. Grant Fujii

5906 N Depauw St

Portland, OR 97203-5116

Mr. Ian Shelley

50 SW 97th Ave

Portland, OR 97225-6902

Mr. Jack West

3914 SE Licyntra Ln

Milwaukie, OR 97222-8835

Mr. James Gilmore

3532 N Missouri Ave

Portland, OR 97227-1167

(503) 249-5170

Ms. Jan McCreary

PO Box 3042

Silver City, NM 88062-3042

Ms. Jan Polychronis

PO Box 639

The Dalles, OR 97058-0639

Ms. Jane Harold

1515 SW Pendleton St

Portland, OR 97239-2617

Ms. Jane Hillemann

PO Box 1600

Vancouver, WA 98668-1600

(360) 696-5094

Mr. Jay Humphrey

25525 S Laura Ln

Estacada, OR 97023-9417

Mr. Jay Russo

1262 Duncan Creek Rd

Stevenson, WA 98648-6177

Mrs. Jennifer Musgrave

8417 N Princeton St

Portland, OR 97203-4845

(503) 349-5623

Ms. Jessi Snow

4304 SE 103rd Ave

Portland, OR 97266-2426

Mr. Jim Clarkson

86083 Cherokee Dr

Eugene, OR 97402-9039

Mr. Jim Gilbert

28696 S Cramer Rd

Molalla, OR 97038-8576

(503) 651-2463

Ms. Joana Kirchhoff

3414 NE 73rd Ave

Portland, OR 97213-5826

(503) 280-9880

Dr. Joel Kay

10707 SE Stanley Ave

Milwaukie, OR 97222-4362

(503) 654-5567

Mr. Joel Rosenblit

2208 Joplin Ct S

Salem, OR 97302-2217

Mr. John Knipe

1071 S Juniper St

Rockaway Beach, OR 97136-

9726

Mr. John Morris

6636 SW Burlingame Ave

Portland, OR 97239-2640

Mr. John Nettleton

4311 SE 37th Ave Apt 21

Portland, OR 97202-3265

(971) 207-1142
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 5 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Mr. John Reynolds

12737 SE 25th Ave

Milwaukie, OR 97222-7938

Mr. John Ritter

109 Montello Ave

Hood River, OR 97031-2235

(541) 806-2680

Mr. John Wadsworth

9271 SW 3rd Ave

Portland, OR 97219-4811

(503) 478-0667

Ms. Joni Zimmerman

1101 W Sheridan St

Newberg, OR 97132-6846

Mr. Joshua Glover

716 Oak St Apt 6

Hood River, OR 97031-1879

(503) 560-3653

Ms. Joy Gohl

725 Snowden Rd

White Salmon, WA 98672-8224

Mrs. Judy Anderson

74015 cougar mt. Rd.

Cottage grove, OR 97424-9234

Ms. Judy Todd

1631 NE Broadway St

# 723

Portland, OR 97232-1425

(503) 260-4995

Ms. Kara Ford

3444 SE Grant St

Portland, OR 97214-5732

(503) 833-2290

Ms. Kathleen Jones

2015 Crest Dr.

Lake Oswego, OR 97034

Ms. Kathryn Elich

10607 E Burnside St Apt 63

Portland, OR 97216-2783

(503) 935-4161

Mrs. Krista Reynolds

1536 NE Saratoga St

Portland, OR 97211-4728

Ms. Laura Hanks

7634 SE Alder St

Portland, OR 97215-2312

Mrs. Laurel Turner

11333 SE Powell Ct

Portland, OR 97266-1758

(503) 760-7400

Mr. Lawrence Nagel

375 Ashland Loop Rd

Ashland, OR 97520-2803

Mr. Leslie Burpo

PO Box 5468

Eugene, OR 97405-0468

(541) 338-7099

Dr. Lester Baskin

2222 NW Lovejoy St Ste 406

Portland, OR 97210-5108

(503) 808-9211

Mrs. Linda Browning

000 0000000 000000

Beaverton, OR 97008

note: address not given

Mrs. Luanne Mierow

26040 S Jewell Rd

Beavercreek, OR 97004-9746

(503) 632-6409

Ms. Lydia Deems

241 Lakeside Dr

White Salmon, WA 98672-9006

Ms. Lynda Cunningham

5505 E Evergreen

Vancouver, WA 98661

Mrs. Lynn Putnam

2368 NW 6th St

Bend, OR 97701-1188

Ms. Marcia Tate

6110 NE 53rd Pl

Portland, OR 97218-2379

Ms. Margaret Keene

97503

White City, OR 97503

note: address incomplete

Ms. Maria White

18880 SW Hart Rd

Beaverton, OR 97007-5623

Ms. Marianne Lawrence

20098 SW Squire Dr

Beaverton, OR 97007-7498

Ms. Marlene Elliott

6105 Bonita Rd Apt K206

Lake Oswego, OR 97035-2243

(503) 484-8146

Mrs. Martha Eslinger

5383 Howell Prairie Rd NE

Silverton, OR 97381-9358

Ms. Martha Stevenson

PO Box 1878

White Salmon, WA 98672-1878

(509) 493-9261

Ms. Mary Bailey

595 NW Lost Springs Ter Unit 

404

Portland, OR 97229-6589

(503) 944-9411

Dr. Mary Blankevoort

31320 NE Hurt Rd

Troutdale, OR 97060-9383

Ms. Mary Grout

9137 NW McKenna Dr

Portland, OR 97229-8039

(503) 292-5440

Ms. Mauria McClay

1005 SE 14th Ave

Portland, OR 97214-2546

Ms. Melba Dlugonski

6735 SE 78th Ave

Portland, OR 97206-7116
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 6 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Ms. Meryle A. Korn

5256 NE 47th Ave

Portland, OR 97218-1966

(503) 281-7475

Mr. Michael Fierst

2811 NE 92nd Ave

Portland, OR 97220-5366

Ms. Monica Gilman

25525 S Laura Ln

Estacada, OR 97023-9417

Ms. Nancy Platner

2150 Elder Rd

Hood River, OR 97031-8534

Mrs. Nicole Sibert-Faaborg

1635 5th St

Hood River, OR 97031-6724

Mr. Norm Enfield

2615 NW 46th Cir

Camas, WA 98607-9141

Ms. Patricia March

723 Lafayette Ave

Columbus, IN 47201-6268

(812) 372-7245

Ms. Patricia Orlinski

10511 W Kingswood Cir

Sun City, AZ 85351-2246

(623) 876-1525

Dr. Paul Metzger

5105 SW Evelyn St

Portland, OR 97219-5869

Dr. Paul Meyer-Strom

4723 SW 50th Ave

Portland, OR 97221-3020

Dr. Paul Torrence

1455 Woodland Dr

Ashland, OR 97520-3451

(541) 708-0153

Ms. Paula Muellner

PO Box 211

Arlington, OR 97812-0211

Mrs. Paula Taccogna

16799 SE Kingsridge Ct

Milwaukie, OR 97267-5247

(503) 513-4951

Mr. Peter von Christierson

1229 - 29thSt.

Port Townsend, WA 98368

Ms. Polly Wood

PO Box 962

Hood River, OR 97031-0032

Ms. Rachel Jordan

285 E 36th Ave

Eugene, OR 97405-4747

(541) 484-9342

Ms. Regna Merritt

260 NW Pittock Dr

Portland, OR 97210-1075

Mr. Richard Schramm

3024 NE Bryce St

Portland, OR 97212-1718

(503) 288-8912

Mrs. Rick Reynolds

1536 NE Saratoga St

Portland, OR 97211-4728

Mr. Rik Masterson

4542 NE 27th Ave

Portland, OR 97211-6524

Mr. Robert and Dolores 

Scheelen

123 Sunrise Ave

Medford, OR 97504-7022

Dr. Ron & Paulette Tatum

17435 SW Blanton St

Aloha, OR 97007-1340

(503) 848-9537

Dr. Ronald Jr

1401 Cross Creek Ln

Hood River, OR 97031-1370

(541) 234-4528

Mr. Ryan Rittenhouse

4806 SE 28th Ave

Apt 719

Portland, OR 97202-4491

(440) 796-9695

Mr. Ryan Wishart

54 N Adams St

Eugene, OR 97402-4274

Dr. Sally Behel

11747 SW Military Ln

Portland, OR 97219-8434

Dr. Sandra Joos

4259 SW Patrick Pl

Portland, OR 97239-7202

(503) 274-8803

Ms. Sandra Williams

2804 SE 27th Ave

Portland, OR 97202-1397

(503) 232-7337

Ms. Sarah Hafer

1401 Wyant Way

Sacramento, CA 95864-2639

(916) 384-9551

Ms. Sharilyn Cohn

128 NE 43rd Ave

Portland, OR 97213-1604

Ms. Sharon Lee

2277 NE Baron Ct

Bend, OR 97701-6606

Ms. Shawn Looney

12937 NW Newberry Rd

Portland, OR 97231-2210

(503) 735-9268

Dr. Stephen Bachhuber

10561 SE Idleman Rd

Happy Valley, OR 97086-6914

(503) 777-8608

Mr. Stephen Gerould

3307 SW Dosch Rd

Portland, OR 97239-1423

(503) 221-7253
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 7 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Mr. Steven Wheeler

5332 NE Broadway St

Portland, OR 97213-2761

Ms. Susan Bissell

2913 NE 29th Ave

Portland, OR 97212-3558

(503) 477-8118

Ms. Susan Dornfeld

PO Box 8305

Portland, OR 97207-8305

Mrs. Susan Hartford

3580 Thomsen Rd

Hood River, OR 97031-8404

Mrs. Sybil Kohl

18103 NE 159th Ave

Brush Prairie, WA 98606-8738

(360) 666-1313

Mr. Ted Light

612 SE 48th Ave

Portland, OR 97215-1721

(503) 445-7643

Ms. Teri Landauer

PO Box 123

Alsea, OR 97324-0123

Mr. Thomas Lange

5420 SW Idaho St

Portland, OR 97221-1621

Mr. Timothy Ulrey

4741 SE 34th Ave

Portland, OR 97202-3315

(503) 771-8303

Mr. William O'Brien

12520 SW Gem Ln Apt 202

Beaverton, OR 97005-1360

Dr. William Whitaker

1108 G Ave

La Grande, OR 97850-2035

Dr. Richard Gorringe, Ph. D.

3574 NE Stanton St

Portland, OR 97212-2747

Dr. Eric Brentlinger

4160 Post Canyon Dr

Hood River, OR 97031-7726

Dr. Edward McAninch

1820 NW Edgehill St

Camas, WA 98607-9364

Ms. Jeanette Ruff

1378 105th Ln NW

Coon Rapids, MN 55433-4889

(503) 927-2874

Mr. Joe Walicki

14760 SW Wheaton Ln

Beaverton, OR 97007-3690

Mr. John Goeckermann

Hugo Road

Grants Pass, OR 97528

note: address incomplete

Mr. Jonathan and Ms. Deanne 

Ater

3344 SW Fairmount Ln

Portland, OR 97239-1446

Ms. Judith Nappe

PO Box 531

North Bonneville, WA 98639-

0531

Mrs. Judy Zettergren, Ph.D.

2693 NW Pinot Noir Dr

Mcminnville, OR 97128-2058

Ms. Juliann a Guy

4559 El Dorado Way

Bellingham, WA 98226-1221

(360) 738-8466

Ms. Karen Grimstad

41025 SE Washougal River Rd

Washougal, WA 98671-5872

Ms. Kate Schmitt

PO Box 29083

Portland, OR 97296-9083

Ms. Kathryn Elich

10607 E Burnside St Apt 63

Portland, OR 97216-2783

(503) 935-4161

Mr. Keith Dunbar

14310 93rd Ave NE

Kirkland, WA 98034-5148

(425) 820-5750

Ms. Laurie E. Milford

1840 Orchard Rd

Hood River, OR 97031-9694

Lee and Cheryl Siebert

1524 SW Miller Ct

Gresham, OR 97080-9358

Ms. Marjorie Johnson

640 NW Freeman Ave

Hillsboro, OR 97124-2833

(503) 640-4682

Mr. Martin McGinn

2719 SE 48th Ave

Portland, OR 97206-1518

(503) 231-0504

Ms. Mary Hayden

18347 S Redland Rd

Oregon City, OR 97045-8063

(503) 631-7040

Mr. Michael Parker

PO Box 65

Oysterville, WA 98641-0065

(360) 665-5077

Patricia Richardson

59051 Elizabeth Lane

St Helens, Or 97051

Robbie Moller

425 Eugene Ave.

Hood River, OR 97031

Ms. Susan O'Hara

PO Box 87575

Vancouver, WA 98687-7575

(360) 604-1205

Mr. Steven Amick

23360 S Viola Welch Rd

Beavercreek, OR 97004-9714
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 8 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Mrs. Lisa Nelski

12306 NE 11th Cir

Vancouver, WA 98684-5869

(360) 449-9897

Ms. Kyenne Williams

2833 N Terry St

Portland, OR 97217-6253

(503) 239-0058

Mr. Chris Carvalho

17717 SW Washington Dr

Aloha, OR 97007-1748

(503) 642-3199

Mr. Jake Culver

1 Main St.

Portland, OR 97202

Dr. Jim Haynes

22 Montello Ave

Hood River, OR 97031-2234

(541) 386-4934
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 9 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Comments by Darryl Usher

Commenter:

Mr. Darryl Usher

9810 NW Gordon Rd

Cornelius, OR 97113-6314

Comment:

I encourage you pass the Troutdale Energy Facility, proposed at the Gateway to the Columbia Gorge.

Response:

Thank you for your comment.

Comments by Paul Wilcox

Commenter:

Paul Wilcox

1030 SW 17th Way

Troutdale, OR 97060

Summary of comments:

The applicant has chosen the monetary path to offset CO2 emissions and will pass the cost on to 

customers; the result is higher rates and more pollution.

The diesel fuel storage capacity of 2.2 million gallons seems excessive.

If air quality in the Portland Metro area is of sufficient concern as to require vehicle smog testing, why 

introduce such a massive single source of pollution into a heavily populated area?

There is no demonstrated need for the excess generating capacity this facility would provide.

Response:

The Oregon Department of Energy administers the CO2 emissions offset program and the Public Utility 

Commission regulates utility costs. DEQ has no role in either the CO2 emissions offset program or the 

regulation of utility costs.

DEQ does not regulate the size of fuel storage tanks. However, DEQ has estimated that 2.2 million 

gallons of diesel (ULSD) equates to roughly 82 hours of operation at the maximum operating rate for all 

turbines. The DEQ permit allows operation on ULSD fuel up to 720 hours per year per turbine.

DEQ is responsible for ensuring that air quality in the entire state meets National Ambient Air Quality 

Standards. Air quality in the Portland Metro area currently meets all National Ambient Air Quality 

Standards but this has not always been the case and extra measures, such as vehicle smog testing, were 

instituted to help air quality meet the ambient air quality standards. DEQ operates the vehicle smog 

testing program in Portland in combination with the industrial source permitting program to help ensure 

that air quality will continue to meet National Ambient Air Quality Standards. As part of the permit 

application, Troutdale Energy Center was required to assess the potential impact of their emissions on the 

air shed’s ability to meet ambient air quality standards. DEQ reviewed that analysis and has determined 
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 10 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

that Troutdale Energy Center successfully demonstrated that emissions from the proposed facility will not 

significantly affect air quality in the Portland Metro area. DEQ also notes that Troutdale Energy Center 

must meet stringent Best Available Control Technology limits that serve to minimize emissions from the 

facility.

DEQ does not regulate energy production and cannot make findings related to generating capacity.

Comments by Allen Johnson, Interlachen Inc.

Commenter:

Allen O. Johnson

President, Interlachen Inc

P.O. Box 96

Fairview, OR 97024

503 512 8222

Comments:

1. Interlachen has its own water district, the Interlachen Water Public Utility District. The Notice of 

Intent mentions the estimated use of 5.3 million gallons of water per day. It says most of it will be 

supplied by the City WPCF, City of Troutdale and Port of Portland. Additionally, it mentions 

applications for water rights for new wells. We are naturally concerned that the aquifer can support the 

additional demand, and request that the impact on the aquifer be explored. 

2. Blue Lake gets its water from a shallower aquifer that is influenced by the Columbia River. When the 

river is low, Blue Lake Residents pay for water fills from the Port of Portland wells to keep Blue Lake's 

water level suitable for recreational purposes. This cost is between one and two thousand dollars per fill 

depending on the amount of water required. If the Troutdale Energy Center is also drawing from this 

aquifer, the residents of Blue Lake may be forced to pay thousands of dollars for additional fills to 

maintain the lake. We would like the impact on Blue Lake, and the recreation at Blue Lake Park, 

considered in the assessment. 

3. Power Lines were constructed to support the Reynolds Aluminum plant that was located near the 

proposed site of the Troutdale Energy Center. These lines were never put into use, as the Reynolds 

facility was closed before they were activated. These lines run right through Interlachen and Fairview 

Lake Property Owners Association properties. The Notice of Intent describes the installation of lines to 

the PGE, PP&L, and one other substation. While connection to the overhead transmission towers is not 

within the scope of this Notice of Intent, we are wondering if connection to the power grid includes plans 

to activate these lines? 

4. Blue and Fairview Lake communities are somewhat isolated from general traffic flow patters, and as 

such we live in a very quiet and peaceful community. We have the occasional train noise and aircraft 

noise from the Troutdale airport. We would like to know what the audible levels of the plant will be? 

Will we hear the constant whine of turbines two miles away? What is the audible levels of the facility at 

certain distances? 
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 11 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

5. Lastly, we would like to know the impact of the combustion process air discharges. 40 tons of NOx 

doesn't mean much to John Doe. How does that equate to the discharges from trucks passing by on I-84 

or jets taking off from PDX? In other words, does this equal the emissions from 600 trucks a day passing 

through our neighborhood? 

Response:

Comments 1 through 3 are outside the scope of the air quality permitting program.

Regarding comment 4, audible noise levels, DEQ’s noise program was terminated in 1991 along with 

funding to administer and enforce the noise regulations. However, the Proposed Order for the Troutdale 

Energy Center issued by the Oregon Department of Energy and dated December 16, 2013 addresses noise 

issues in several locations in the proposed order. The proposed order (at least as of February 5, 2014) is 

available at:

http://www.oregon.gov/energy/Siting/docs/TEC/TEC_proposed_order_121613.pdf

Regarding comment 5, the daily amount of emissions from Troutdale Energy Center might be equivalent 

to the amount of emissions from several hundred trucks, but the pollution effects of Troutdale Energy 

Center and several hundred trucks per day passing through the neighborhood would be quite different.

Emissions from trucks passing through the neighborhood would occur in close proximity to residents. 

While DEQ has not performed a detailed analysis of the effect this would have, it is likely that pollutant 

levels would build up locally and some air quality standards may be exceeded. For example, a 1-hour 

ambient air quality standard for nitrogen dioxide (NO2) was established in recent years by the U.S. 

Environmental Protection Agency (EPA) and it is generally believed by both EPA and DEQ that the most 

likely locations for this standard to be exceeded are near heavily travelled highways.

Regarding the effects of Troutdale Energy Center’s emissions, DEQ required Troutdale Energy Center to 

perform a modeling analysis of the facility’s emissions. DEQ reviewed and approved the analysis results 

and methodology.

The analysis looked at attainment with the National Ambient Air Quality Standards considering all 

sources of air pollution, and the contribution of emissions from Troutdale Energy Center compared to 

Significant Impact Levels. The analysis indicates that emissions from the facility will comply with 

Oregon’s regulations for the protection of air quality and in general will not cause air quality to exceed 

any National Ambient Air Quality Standards. The modeling did show exceedances of the 1-hour NO2

National Ambient Air Quality Standard at five locations. At four of those locations, the contributions 

from the Troutdale Energy Center were very low and not considered significant, while at the fifth location 

(near the paper mill in Camas, Washington) the contribution was higher but still below a level considered 

significant. In other words, the modeled exceedances of the 1-hour NO2 National Ambient Air Quality 

Standard are mainly the result of other emissions sources and Troutdale Energy Centers’ contributions to 

the exceedances were below significant impact levels.

The modeling review, which contains the results of this assessment is attached to the review report for the

permit and is available from DEQ.
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 12 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Comments by NEDC, Friends of the Columbia Gorge and Columbia Riverkeeper

Commenters:

Air Quality Group, Northwest Environmental Defense Center

JJ England

Shanna Fricklas

Matthew Ring

Heather Fossity

Rachel Morris

YoungWoo Joh

Erica Nist-Lund

Friends of the Columbia Gorge

Columbia Riverkeeper

Comment:

II.A. Unrestricted permission to use ultra low sulfur distillate fuel 720 hours/year, without specifying this 

as solely a backup fuel for EU2/EU3, does not constitute BACT.

This ACDP’s review report explains that “[t]he two simple-cycle combustion turbines [EU2/EU3] may 

burn ULSD at any time, with each limited to 720 hours per year.” TEC Permit Review Report, at 5. This 

is as compared to the combined cycle turbine, EU1, which is only permitted to burn ULSD during periods 

of natural gas curtailment. Permitting EU2/EU3 to combust ULSD in any capacity other than as a backup 

fuel or during periods of natural gas curtailment does not meet the requirement for BACT for NOx, CO, 

or VOC. For this permit to meet the requirement of BACT, it must require combustion of the cleanest 

burning fuel (natural gas) at all times except when backup fuel must be used (e.g., due to natural gas 

curtailment), at which time the cleanest burning backup fuel (ULSD) must be used. This approach yields 

the best control technology, accounting for the project’s purpose, feasibility, economic, and other impacts. 

The permit does not make this distinction, resulting in a flawed top-down BACT analysis.

Response:

In the draft permit, DEQ did not propose to limit the hours of operation on ULSD as part of the BACT 

determination. DEQ did include limits on the hours of operation on ULSD as an “Owner requested 

limitation” under the authority of OAR 340-226-0120(1), Operating and Maintenance Requirements.

"Best Available Control Technology" or "BACT" is defined in Oregon Administrative Rule 340-200-

0020(15) as follows:

(15) "Best Available Control Technology" or "BACT" means an emission limitation, including, 

but not limited to, a visible emission standard, based on the maximum degree of reduction of each 

air contaminant subject to regulation under the Act which would be emitted from any proposed 

major source or major modification which, on a case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, is achievable for such source or 

modification through application of production processes or available methods, systems, and 

techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for 

control of such air contaminant. In no event may the application of BACT result in emissions of 

any air contaminant that would exceed the emissions allowed by any applicable new source 

performance standard or any standard for hazardous air pollutant. If an emission limitation is not 

feasible, a design, equipment, work practice, or operational standard, or combination thereof, may 
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 13 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

be required. Such standard must, to the degree possible, set forth the emission reduction 

achievable and provide for compliance by prescribing appropriate permit conditions.

DEQ’s BACT determination established emission limitations for the turbines for both fuel types, with the 

exception of GHGs where a single limitation covers both fuels. Although multiple BACT limitations for a 

single device and pollutant are sometimes specified by permitting authorities, DEQ notes that the 

definition of BACT does not require multiple limitations. DEQ’s BACT determination therefore meets 

the definition of BACT as it stands and is not deficient.

However, DEQ agrees with the concept of further limiting the use of ULSD to the extent reasonably 

possible given the nature of the facility, and in consideration of comments received, reviewed condition 

30.

Condition 30 in the draft permit stated that the combustion turbines must burn only natural gas except as 

follows:

 The combined cycle combustion turbine (EU1) may burn ULSD fuel in the event of natural gas 

curtailment, not to exceed 720 hours per calendar year. (emphasis added)

 The simple cycle combustion turbines (EU2 and EU3) may burn ULSD fuel, not to exceed 720 

hours per turbine per calendar year.

In reviewing this condition, DEQ first made an effort to better understand the meaning of “natural gas 

curtailment”. Oregon law provides that certain government entities, such as the Public Utility 

Commission (PUC), may curtail natural gas in the event of an emergency. PUC regulations also require 

natural gas utilities to prepare plans for the curtailment of natural gas deliveries in the event of a situation 

that threatens the long-term deliverability of natural gas. DEQ contacted Northwest Natural Gas to 

discuss curtailments and learned that the utility may curtail gas deliveries when local demand exceeds the 

utility’s ability to supply gas. This usually occurs during extreme cold weather and in a limited 

geographic area. Curtailment is implemented through rate schedules that effectively establish gas user 

priorities. Firm price customers have top priority, and this category includes residential customers. Large 

industrial customers that can use a backup fuel often choose to be on an interruptible rate schedule, which 

includes a significant cost penalty if the customer continues to use natural gas after being ordered to 

curtail the use of gas. If gas demand exceeds the ability to supply, interruptible customers in the affected 

area are contacted and told to curtail the use of gas. Curtailment is not effected by physically shutting off 

the flow of gas, but by the price penalty in the interruptible rate schedule.1

DEQ requested Troutdale Energy Center clarify their intentions with respect to the use of ULSD fuel. 

Troutdale Energy Center provided the following information on December 23, 2013:

“Troutdale Energy Center, LLC (TEC) has requested the ability to use ULSD instead of natural 

gas at its proposed combustion turbine facility in Troutdale, OR (the Facility) during actual or 

effective deliverability events related to either natural gas commodity supply or transportation 

curtailment. Natural gas delivered to the Facility will be sourced from Canada, the Rocky 

Mountains and the San Juan natural gas basins from the Williams’ Northwest Pipeline. The 

Northwest Pipeline is a 3,900-mile bi-directional gas transmission system crossing the states of 

Washington, Oregon, Idaho, Wyoming, Utah and Colorado. During periods of high demand 

 

1 DEQ subsequently learned that Northwest Natural Gas would not be the supplier to Troutdale Energy Center, but 

the information from Northwest Natural was still informative.
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 14 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

(typically cold temperatures in Canada, the Rocky Mountain region and/or the Four Corners 

region of the southwest US), natural gas prices can exhibit extreme price volatility that make it 

infeasible to use. During periods of high demand Williams may also curtail transportation rights 

along the over-subscribed Northwest Pipeline and limit transportation to Local Distribution 

Companies that serve higher priority residential customers. In the case of extreme price volatility 

or a transportation curtailment, TEC would use ULSD as the Facility’s fuel. TEC is not 

proposing to use ULSD as fuel in the Facility’s combustion turbines except during actual or 

effective curtailment events. The exception to this rule would be during commissioning and 

performance testing when TEC would employ ULSD in the Facility’s combustion turbines even 

if natural gas is available.”

DEQ also found the following document published by the US Energy Information Administration: 

An Analysis of Price Volatility in Natural Gas Markets, Energy Information Administration, Office of Oil 

and Gas, August 2007, available at: 

http://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2007/ngprivolatility/ngprivolatility.pdf .

This document provided a detailed technical analysis of natural gas price volatility and the factors that 

affect prices and volatility. 

The document includes the following statements:

“This article presents an analysis of price volatility in the spot natural gas market, with particular 

emphasis on the Henry Hub in Louisiana.” (page 1)

“Factors on the supply side that may affect prices, and hence volatility, include variation in 

natural gas storage, production, imports, or delivery constraints.” (page 2)

“Disruptions caused by severe weather, operating mishaps, or planned maintenance can also 

cause short-term tightness in natural gas supply.” (page 2)

“On the demand side, temperature changes tend to be one of the strongest short-term influences. 

During cold months, residential and commercial end users consume more natural gas for heating 

needs, which places upward pressure on prices. If unexpected or severe weather occurs, the effect 

on prices intensifies because supply is often unable to react quickly to the short-term demand 

response, especially if the natural gas transportation system is operating at full capacity. Under 

these conditions, prices must rise high enough to reduce the demand for natural gas.” (pages 2 

and 3, emphasis added)

“The highest volatility levels in any year tend to occur from October through February. December 

through February are generally the coldest months of the year, and demand for natural gas rises 

sharply during these months as heating needs dominate the market.” (page 6)

Based on the above, Troutdale Energy Center’s proposed use of ULSD in all turbines is consistent with

limiting the use of ULSD to only those times when the natural gas supply is “curtailed”, where DEQ now 

understands curtailment to mean curtailment initiated by a government entity, a gas supplier or gas 

transporter, as well as “effective curtailment” as indicated by extreme price volatility.
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 15 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

DEQ does not have expertise in the area of natural gas pricing and is unable to precisely define “extreme 

price volatility”. However, DEQ notes that extreme price volatility might reasonably be indicated by 

sharp upward “spikes” in natural gas spot prices. Alternatively, actual information from gas suppliers or 

transporters might be available and could be used to show gas deliverability problems.

Finally, the use of ULSD for maintenance and testing purposes needs to be specifically allowed.

DEQ has revised condition 30 in the final permit to state that the combustion turbines must burn only 

natural gas except as follows:

 All combustion turbines (EU1, EU2 and EU3) may burn ULSD fuel for the purpose of 

commissioning, equipment maintenance and testing, and emissions source testing. Such use must 

be held to the minimum amount required to accomplish the activity.

 All combustion turbines (EU1, EU2 and EU3) may burn ULSD fuel in the event of natural gas 

curtailment, not to exceed 720 hours per turbine per calendar year.

o For the purpose of this permit condition, curtailment means actual or effective 

deliverability events related to either natural gas commodity supply or transportation 

curtailment.

o Actual or effective deliverability events may be demonstrated by keeping records of 

announcements by gas suppliers, gas transporters, or government entities; or by keeping 

records demonstrating extreme price volatility in day to day spot prices for the gas 

pipeline that supplies the facility.

Monitoring condition 31 has also been revised to account for the changes to condition 30.

Comment:

II.B. DEQ should exercise its discretionary authority to implement BACT during periods of startup and 

shutdown for EU1/EU2/EU3.

Given the purpose of this plant as a wind-integration facility, DEQ and the permittee anticipate 1,000 

annual startup/shutdown cycles for the simple cycle units and approximately 200 annual startup/shutdown 

cycles for the combined cycle unit, totaling 321-330 hours per turbine per year. 

Given the substantial number of startup/shutdown cycles expected at this facility, NEDC requests that 

DEQ exercise its discretion in establishing a secondary BACT standard for periods of startup and 

shutdown. See, e.g., In re: Tallmadge Generating Station, PSD Appeal No. 02-12, (EAB, May 22, 2003) 

(discussing BACT applicability in startup/shutdown context). Such action would serve the public interest 

by protecting public health and the environment because a significant portion of this facility’s emissions 

will occur during startup/shutdown.

Response:

DEQ does not agree with commenters.

The applicant submitted the following information in the permit application:

 the time periods required for startups and shutdowns, and

 estimates of the emissions that would occur during those time periods.
DEQ Response to Comments – Troutdale Energy Center

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Permit writer: George Davis

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503-229-5534

In essence, a startup will take a certain amount of time, and during that time there will be a certain amount 

of emissions. Alternatively, a startup will cause a certain amount of emissions, and those emissions will 

occur over a certain period of time. In other words, the amount of time required for a startup and the 

amount of emissions that occur during a startup are directly related to one another such that specifying the 

time also specifies the emissions and specifying the emissions also specifies the time. Therefore, with 

regard to startups and shutdowns, a time limit or an emissions limit are equivalent and either serves to 

limit the other. DEQ therefore concludes that the time limits alone are sufficient and sees no need to 

change the BACT determination for startups and shutdowns.

Comment:

II.C. This permit’s GHG BACT determination differs significantly from determinations made by DEQ’s 

peer agencies in other jurisdictions for the same equipment employed at this plant.

NEDC is concerned that DEQ accepted the permittee’s GHG BACT analysis and rationale underlying this 

analysis, even though other facilities employing the same equipment for the same purpose are currently

permitted to emit significantly less GHG than has been proposed here. The permittee set forth two 

rationales for a 1000 lb CO2e/MWh limit for EU1 and 1707 lb CO2e/MWh limit for EU2/EU3. First, it 

explained that TEC’s wind-integration function necessitates a higher limit because the facility necessarily 

burns more fuel while ramping up electric production. Second, it explained that the permit incorporates 

ULSD, a higher-emitting fuel. TEC Permit Review Report, at 19. Each of these reasons is flawed, leading

to a BACT analysis that is legally deficient and insufficiently protective of global climate.

First, only the simple cycle turbines are intended to rapidly ramp production up and down. EU1, the 

combined cycle unit, is not nearly as well suited for this task and is intended to provide baseload or midpeaking power as opposed to rapid wind-integration capability. This is further evidenced by the permitted 

number of startup/shutdown cycles for EU1. As such, the permittee’s first rationale simply does not apply 

to EU1—it only applies to EU2/EU3. NEDC requests that DEQ reconsider the GHG BACT 

determination for EU1 in light of that emission unit’s express function and purpose. Upon this review, 

DEQ should consider other recently permitted combined cycle turbines that have adhered to GHG limits 

substantially lower than 1000 lb CO2e/MWh. See, e.g., FPL Port Everglades Combined Cycle BACT 

Determination, at 13 (832 lb CO2e/MWh for natural gas; 1,176 lb CO2e/MWh for ULSD), available at

http://www.epa.gov/region4/air/permits/ghgpermits/porteverglades/PortEverglades_PD.pdf.

Second, the permit’s GHG BACT analysis is flawed because it combines emissions for two very different 

fuels under one standard. Most of this ACDP’s emission-limiting permit conditions explicitly establish 

different limits for natural gas and ULSD combustion. Without any reason given, however, the permit 

treats GHGs differently by combining the GHG emission limit for both fuels under one standard. This 

approach yields an improper BACT determination because it allows TEC to benefit from a more relaxed 

GHG emission limit resulting from incorporation of ULSD into the emission rate, even if it only ever 

burns natural gas. Moreover, EPA has determined in its own permitting decisions that combining ULSD 

and natural gas into one BACT emission limit is not appropriate. Id.

Therefore, NEDC suggests that DEQ cure this legal deficiency in the permit by treating GHGs the same 

way as it treated most every other pollutant in this permit—by establishing separate standards for natural 

gas combustion and ULSD combustion. Doing so will require TEC to meet the limit actually applicable to 

the facility’s operating situation (i.e., when combusting natural gas or ULSD). Moreover, it will establish 

a useful BACT standard that can be relied upon by other, similar facilities. For example, the Perennial-
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

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Permit writer: George Davis

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503-229-5534

WindChaser plant, which recently submitted a PSD permit application to DEQ, has indicated its GHG 

BACT analysis is based on the determination for this permit.

Most importantly, at least one recently-permitted facility uses the exact same simple cycle turbines for the 

exact same purpose as TEC, and yet that facility received a substantially lower GHG BACT 

determination. That facility, the Pio Pico Energy Center, permitted by EPA, incorporated several GE 

LMS100 simple cycle turbines in order to integrate wind and solar energy into the grid. The turbines were 

permitted 500 startup/shutdown cycles per year. EPA determined GHG BACT for that facility was 

1,328lb/MWh, approximately 23% less than proposed for TEC. See PSD Permit for Pio Pico Energy 

Center, available at http://www.regulations.gov/#!documentDetail;D=EPA-R09-OAR-2011-0978-0014; 

see also BACT Determination for Puget Sound Energy Fredonia Station, at 5-31, available at 

http://www.ecy.wa.gov/programs/air/psd/PSD_PDFS/PSE-Fredonia_Rev2_111031.pdf (LMS100 GHG 

BACT of 1,138 lb CO2e/MWh, but no indication of using this facility for windpower integration).

Based on the above, NEDC requests that DEQ fully reconsider its GHG BACT determination for both the 

combined cycle and simple cycle units at TEC. This analysis should provide separate standards for natural 

gas and ULSD. For natural gas specifically, a determination for EU1 should, at minimum, be below 850 

lb CO2e/MWh based on review of other existing permits. For EU2/EU3, 1,328 lb CO2e/MWh appears 

feasible and appropriate based upon the Pio Pico Energy Center permitting decision, and DEQ should 

consider adopting this standard as BACT for these emission units.

Response:

DEQ has reconsidered the GHG BACT analysis as requested by the commenters. DEQ reviewed the PSD 

permits referred to by commenters, and requested additional information from the applicant about 

proposed turbine operating scenarios and turbine performance and emissions under a number of operating 

loads.

Regarding turbine operating scenarios, the applicant provided the following:

“The combined-cycle power plant is intended to provide base load power. However, as with 

most generation units in the Pacific Northwest, due to the variability of renewable and hydrogeneration output, the combined-cycle power plant at the Troutdale Energy Center could also be 

load following. The combined-cycle plant is therefore not comparable to base load resources in 

other parts of the country where intermittent renewable energy resources do not represent a 

significant portion of the region’s capacity and energy. The combined-cycle plant will follow net 

load after hydropower and wind generation which are typically the first call resources. The 

combined-cycle power plant is not designed to provide power for short term, sudden demand 

surges. That sort of peak duty cycle would normally be met through simple-cycle combustion 

turbines. However, the combined-cycle plant is expected to operate as low as 50 percent load 

(burning natural gas) so as to be able to ramp up more efficiently and fill base load needs as wind 

and hydro resources diminish. This flexibility reduces the need to operate less efficient resources 

and makes the combined-cycle unit an optimal reserve generation resource for balancing 

unscheduled variations in output from variable output generation resources like wind turbines.”

2

“The simple-cycle power plant is intended to provide peaking capacity and its output can be 

changed almost instantaneously to facilitate the integration of variable output generation 

 

2 Letter to George Davis, Oregon DEQ, from Troutdale Energy Center, December 9, 2013, page 3
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

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Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

resources like wind and solar generation. This is in contrast to the typical simple-cycle generation 

unit that is operated as a load following and cycling resource. The significant supplies of wind 

generation in the Northwest (particularly along the Columbia River Gorge) exhibit rapid and 

concentrated fluctuations in output and, when combined with forecast errors, create significant 

energy imbalances in real time that have been well documented by large Northwest transmission 

system operators (e.g. BPA, PacifiCorp, PGE).”

3

DEQ concludes that all turbines at the proposed facility are intended to operate at variable loads and to 

rapidly ramp up power production. Regarding turbine performance and GHG emissions, the applicant 

provided information in two tables4. The relevant information from the tables is shown below:

Low Load Operating and Performance Scenarios:

Table 1

Simple Cycle Combustion Turbine 

Proposed BACT: Annual Average 1,707 CO2 lb/MWh 

Fuel Type NG NG NG NG ULSD ULSD ULSD NG ULSD

Load Level (%) 100 75 50 25 100 75 50 SUSD SUSD

Gross Plant Output (kW/hr, with 10% 

degradation factor) 95,663 71,545 47,467 23,341 91,574 68,675 45,791

Fuel Flow (MMBtu/hr, HHV)1 929.5 736.4 555.2 356.6 893.6 716.4 541

CO2 Emissions (lb/MWh equivalent 

gross w/10% degradation) *

1,136 1,203 1,367 1,786 1,591 1,701 1,927

CO2 (tons/hr) 54 43 32 21 73 58 44 30 40

Hours / Yr ** 0 438 1,840 4,713 0 0 1,440 203 127

CO2 (tons) 0 18,854 59,702 98,239 0 0 63,530 6,097 5,081

Output (MWh equivalent, gross) 0 31,337 87,319 110,001 0 0 65,946 0 0

Notes: * GHG Emission Factors provided by 40 CFR Part 98, Table C-1

** Estimated based on a potential operating scenario

Table 2

Combined Cycle Combustion Turbine 

Proposed BACT: Annual Average 1,002 CO2 lb/MWh

HRSG Firing1 Unfired Fired Unfired Unfired Unfired Unfired

Fuel Type1 NG NG NG NG ULSD ULSD NG ULSD

Load Level (%) 100 100 75 50 100 60 SUSD SUSD

Gross Plant Output (kW/hr, with 10% 

degradation factor) 359,622 411,660 278,514 210,618 285,777 185,508

Fuel Flow (MMBtu/hr, HHV) 2,595 3,092 2,106 1,662 2,298 1,599

CO2 Emissions (lb/MWh equivalent 

gross w/10% degradation) *

844 878 884 923 1,311 1,406

CO2 (tons/hr) 152 181 123 97 187 130 97 130

Hours / Yr ** 613 613 613 5,158 0 1,440 277 45

CO2 (tons) 93,027 110,827 75,485 501,178 0 187,760 26,851 5,853

Output (MWh equivalent, gross) 220,520 252,430 170,785 1,086,455 0 267,158 0 0

Notes: * GHG Emission Factors provided by 40 CFR Part 98, Table C-1

** Estimated based on a potential operating scenario

 

3 Letter to George Davis, Oregon DEQ, from Troutdale Energy Center, December 9, 2013, page 4

4 Tables were originally provided in the letter referenced in footnotes 1 and 3, but contained errors. Corrected tables 

were provided by email on December 20, 2013.
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

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Permit writer: George Davis

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503-229-5534

The Proposed BACT: Annual Average values in the first row of each table are the total annual CO2

emissions divided by the total annual electrical power output for the scenarios in the tables, calculated as 

follows:

[sum of all values in the row labeled CO2(tons)] x 2000 lb/ton

[sum of all values in the row labeled Output (MWh equivalent, gross)]

Parts of the tables are copied below, and DEQ has added lines showing the Percent increase in CO2 

emissions in lb/MWh over full load. For both types of turbine, examination of the tables shows that the 

emission rate in lb/MWh becomes higher at low load. The calculated Percent increase in CO2 emissions 

in lb/MWh over full load also illustrates this increase.

Simple Cycle Combustion 

Turbine

Fuel Type NG NG NG NG ULSD ULSD ULSD

Load Level (%) 100 75 50 25 100 75 50

CO2 Emissions (lb/MWh 

equivalent gross w/10% 

degradation)21,136 1,203 1,367 1,786 1,591 1,701 1,927

Percent increase in CO2 

emissions in lb/MWh over 

full load -- 6% 20% 57% -- 7% 21%

Combined Cycle Combustion 

Turbine 

HRSG Firing1 Unfired Fired Unfired Unfired Unfired Unfired

Fuel Type1 NG NG NG NG ULSD ULSD NG

Load Level (%) 100 100 75 50 100 60 SUSD

CO2 Emissions (lb/MWh 

equivalent gross w/10% 

degradation)2844 878 884 923 1,311 1,406

Percent increase in CO2 

emissions in lb/MWh over 

full load -- -- 5% 9% -- 7%

Tables 1 and 2 (on page 18) also show GHG emissions in tons per hour for each scenario. DEQ notes that

pollutant emission rates are typically at a maximum when equipment is operated at its maximum rate, and 

indeed the tables indicate that GHG emission in tons per hour are at their maximum at full load and are 

lower at low loads. However, and perhaps counter-intuitively, GHG emissions in pounds per megawatthour are at their minimum at full load and are higher at low loads. DEQ understands that all combustion 

turbines exhibit the same basic performance characteristics; that is, they operate at maximum efficiency at 

full load and at lower efficiency at lower loads. Lower efficiency at lower loads means using more fuel 

per MWh generated. Since GHG emissions are directly related to the amount of fuel used, using more 

fuel per MWh at lower loads also means emitting more GHGs per MWh.

DEQ recognizes that operating combustion turbines at low load, where they are less efficient, seems to 

contradict the idea that BACT for combustion-derived GHGs is generally considered to be the use of 

equipment that exhibits the highest energy efficiency.GHG BACT for this type of facility must be 

considered within the context of electrical power generation overall, particularly wind energy. 

Availability and reliability of wind may vary unexpectedly resulting in variable output from wind 
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Permit writer: George Davis

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503-229-5534

generation resources. One of the stated purposes of the Troutdale Energy Center is to integrate with wind 

power, which means this facility is intended to provide rapidly available energy to “fill in” when wind 

power declines. This results in the need to operate this facility at varying loads, a mode of operation that 

is inherently less efficient than operating continuously at full load. This is an unavoidable consequence 

that will often result in a higher GHG emission rate, on a lb/MWh basis, when the facility is operating.

The fact that wind power is available at times means that, generally, less fuel overall must be burned to 

generate electricity. So, while an individual generating facility may have to operate in a less efficient 

manner, the electrical generating system as a whole is able to be more energy efficient, thus broadly 

achieving the energy efficiency goal of GHG BACT. Finally, DEQ notes that while low-load operation is 

less efficient, the actual GHG emission rate on a ton per hour basis is lower when operating at low load.

DEQ reviewed the GHG BACT limits for the facilities identified by the commenters, Port Everglades 

Energy Center5, Pio Pico Energy Center6and Puget Sound Energy Fredonia Generating Station 

Expansion Project7. The GHG BACT limits for these facilities are show below, along with the full load 

GHG emission rates for the turbines at the proposed Troutdale Energy Center (TEC):

Facility Turbine 

generator 

type

GHG BACT 

limit

lb/MWh

TEC turbine emission rate at 

full load with 10% 

degradation factor

lb/MWh

Port Everglades Energy Center

Project consists of three 250 MW 

combustion turbine generators plus one 

500 MW steam turbine generator

without duct burners

Combined 

cycle

832 lb/MWh 

(natural gas)

1,176 lb/MWh 

(ULSD)

844 lb/MWh (natural gas)

without duct firing

878 lb/MWh (natural gas)

with duct firing

1,591 lb/MWh (ULSD)

Pio Pico Energy Center

Project consists of GE LMS100 natural 

gas-fired combustion turbine generators

Simple 

cycle

1,328 lb/MWh

(natural gas)

1,136 lb/MWh (natural gas)

Fredonia Generating Station Expansion 

Project

Project has several combustion turbine 

options, including 

two GE LMS100 turbines

Simple 

cycle

1,138 lb/MWh

(natural gas)

1,136 lb/MWh (natural gas)

DEQ notes that the GHG emission rates for the turbines at the proposed Troutdale Energy Center at full 

load when firing natural gas are generally comparable to the BACT limits shown above. DEQ further 

notes that the documents referenced by the commenters did not discuss GHG emission rates in lb/MWh at 

low load, nor did DEQ find any other documents related to these facilities that discussed GHG emission 

rates in lb/MWh at low load. It appears to DEQ that the BACT limits were set at the full load emission 

rates, and that the BACT limits above would limit the operation of these facilities to full or close to full 

load at all times. As discussed above, consideration of emission rates at low load is appropriate in the 

BACT determination for the TEC facility given its relation to wind power.

 

5 Referenced on page 17 of this document

6 Referenced on page 18 of this document

7 Referenced on page 18 of this document
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503-229-5534

A BACT determination cannot be used to redefine a facility. The stated purpose of the proposed 

Troutdale Energy Center is to provide base load, load following and peaking power, and this requires the 

facility to operate all combustion turbines at low loads much of the time. DEQ believes that setting GHG 

BACT limits at levels that can only be achieved at or near full load would require the applicant to operate 

only at or near full load at all times. This would prevent the facility from operating in the intended manner 

and would constitute redefining the facility to a base-load only generating plant. Therefore DEQ cannot 

set GHG BACT limits at or near levels that can only be achieved at full load.

The applicant has presented potential operating scenarios in Tables 1 and 2 (on page 18) which might 

reasonably occur in practice and which DEQ believes represent reasonable worst-case scenarios. The 

GHG BACT limits proposed in the draft permit are based on these scenarios and properly take into 

account the higher GHG emission rates (on a lb/MWh basis) at lower loads.

In consideration of all of the above, DEQ does not agree with commenters and finds that the GHG BACT 

limits proposed for Troutdale Energy Center’s combustion turbines are reasonable and correct for the way

this particular facility is intended to operate.

With respect to the comment that DEQ should establish separate GHG BACT limits for natural gas and 

ULSD operation, DEQ notes that the proposed GHG BACT limits differ significantly from other

proposed BACT limits in the draft permit in that the GHG BACT limits are long-term limits (annual 

average) as opposed to short-term limits (averaged over hours). DEQ also notes that the proposed GHG 

BACT limits are based on a reasonable annual operating scenario that accounts for all potential modes of 

operation. If separate GHG limits were established for natural gas and ULSD, they would be established 

in much the same way, based on potential operating scenarios that are reasonably possible and reflect the 

stated purpose of the facility. Recalculating limits in this manner will not serve to further limit GHG 

emissions from this facility. DEQ therefore does not agree with commenters that there is a legal 

requirement to establish separate GHG BACT limits in terms of lb/MWh for natural gas and ULSD.

Comment:

III.DEQ may wish to update permit conditions 47 and 49 to account for recently proposed GHG NSPS 

covering new stationary combustion turbines.

Permit conditions 47 and 49, together, anticipate promulgation of a GHG NSPS covering EU1, the 

combined cycle unit, as an “affected source” and anticipate that EPA will codify this rule in 40 CFR 60, 

subpart TTTT. EPA’s recently proposed GHG NSPS, however, suggests that it may be prudent for DEQ 

to make several changes to these permit conditions.

First, EPA has indicated it may codify this rule under either subpart TTTT or subpart KKKK. See 

Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility 

Generating Units, EPA-HQ-OAR-2013-0495; FRL-9839-4, at 37, available at

http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposal.pdf. Conditions 47 and 

49 do not reflect this possibility.

Second, EPA’s proposed rule has the potential to also cover EU2/EU3 as affected sources if those 

emission units sell more than one-third of their potential output capacity to the grid on a three year rolling 

basis. Id. at 81-87. NEDC recognizes that this scenario is unlikely because these units are not intended to 

provide baseload power. Nonetheless, the wind-shaping purpose of these emission units and the lack of 
DEQ Response to Comments – Troutdale Energy Center

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Permit writer: George Davis

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503-229-5534

data as to hours of operation or total sales for these emission units in the review report has led the 

commenters to bring this issue to DEQ’s attention. If the permittee intends to sell more than one-third of 

EU2/EU3’s potential output, the units will be unable to meet EPA’s proposed NSPS of 1,100 lb 

CO2e/MWh based on the BACT determination for those units.

Response:

Conditions 47 and 49 are monitoring requirements for CO2 and ammonia, respectively, and do not refer to 

the requirements of Subpart TTTT. DEQ believes commenters are referring to condition 44 of the draft 

permit, which requires the permittee to comply with 40 CFR Part 60 Subpart TTTT. DEQ agrees with 

commenters and has revised this condition to read as follows:

“Upon the dates specified in 40 CFR Part 60 Subpart KKKK or TTTT, whichever applies, the permittee 

must comply with the relevant Subpart KKKK or TTTT CO2 standards as applicable to EU1, EU2 and 

EU3, including all applicable performance testing, recordkeeping and reporting requirements.”

DEQ appreciates commenters bringing the potential compliance issue to DEQ’s attention. DEQ will 

review compliance with Subpart KKKK or TTTT, whichever is applicable, after it is promulgated. DEQ 

also expects to expand condition 44 in a future permit action to add the necessary details from the final 

version of whichever rule EPA revises.

Comment:

IV. Conditions 50 and 51 will not provide DEQ adequate notice if this facility is in noncompliance with 

emission limits established in this permit.

This ACDP establishes emission limits and PSELs for PM and VOCs. Condition 50 provides that TEC 

must undertake a source test every 5 years for VOCs. Condition 51 provides that TEC must undertake a 

source test for PM every 10 years when combusting natural gas, and never, except immediately following 

construction, when combusting ULSD.

This pre-construction permit, as written, is intended to eventually be turned into a Title V operating 

permit. 42 USC § 7661(c) provides that a Title V operating permit must contain “conditions as are 

necessary to assure compliance with applicable requirements” of the Clean Air Act. The 2010 Stationary 

Source Compliance Monitoring Strategy, EPA’s definitive guidance on stationary source monitoring 

developed in conjunction with the National Association of Clean Air Agencies, states that a full 

compliance evaluation “should be conducted, at a minimum, once every two Federal fiscal years at all 

Title V major sources.” Compliance Strategy, at 9, available at 

http://www.epa.gov/compliance/resources/policies/monitoring/caa/cmspolicy.pdf . Per that guidance, a 

full compliance evaluation incudes source testing for all regulated pollutants at a facility.

Conditions 50 and 51 do not comply with 42 USC § 7661(c) because source tests that are spaced five or 

ten years apart (or in the case of PM from ULSD combustion, are simply never conducted after 

construction) cannot possibly provide DEQ with sufficient information to “assure compliance” with PM 

and VOC limits established by DEQ. Nor do conditions 50 and 51 comport with the spirit or meaning of 

the Monitoring Strategy because source testing at 5-10 year intervals is substantially longer than the two 

years recommended in the guidance. In other words, a source test conducted five or ten years earlier will 

not be a reasonable proxy for current emissions. Therefore, NEDC requests that DEQ change permit 

conditions 50 and 51 to require source testing when burning natural gas and ULSD every 14 months for 

VOC and PM. This should not be a significant hardship for the permittee, as it is already required to 
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503-229-5534

undertake source testing on this 14-month schedule for NOx and CO. See TEC Permit, Condition 48. 

Most importantly, though, a 14-month schedule should provide DEQ with sufficient information to

provide it with reasonable assurance that TEC is in compliance with its VOC and PM limits.

Response:

Commenters cite EPA’s 2010 Stationary Source Compliance Monitoring Strategy, and state “Per that 

guidance, a full compliance evaluation incudes source testing for all regulated pollutants at a facility.”8

DEQ disagrees with this statement and point out that the 2010 Stationary Source Compliance Monitoring 

Strategy states, on page 5, that a Full Compliance Evaluation includes “A stack test where there is no 

other means for determining compliance with the emission limits. In determining whether a stack test 

is necessary, States/locals should consider factors such as: size of emission unit; time elapsed since 

last stack test; results of that test and margin of compliance; condition of control equipment; and 

availability and results of associated monitoring data.” DEQ will be inspecting the facility consistent 

with DEQ’s Compliance Monitoring Strategy. DEQ also considered the factors discussed below in 

determining the frequency for certain stack tests.

Both VOC and CO are byproducts of incomplete combustion, and emissions of both would be controlled, 

to some extent, by the oxidation catalyst emission control system that is required for all three turbines. 

DEQ regards CO as a reasonable surrogate for VOC9and compliance with the CO limit reasonably 

implies compliance with the VOC limits. DEQ therefore does not agree that VOC testing every 14 

months is necessary.

However, upon reconsideration of the proposed testing schedule, DEQ has revised condition 50 to require 

additional testing while using ULSD as follows:

Following the initial test, subsequent tests while burning ULSD must be performed as follows:

1. not more than 60 months after the first test; and

2. thereafter, not more than 10 years after the most recent test.

The requirements for testing while using natural gas were not changed.

Permit condition 51 requires emissions testing of the turbine exhausts for PM. Combustion of natural gas 

produces very little PM and the amount of PM produced is not likely to change over time. Therefore DEQ 

does not believe that more frequent PM testing while using natural gas is needed.

Upon reconsideration of the proposed testing schedule, DEQ has revised condition 51 to require 

additional testing while using ULSD as follows:

Following the initial test, subsequent tests while burning ULSD must be performed as follows:

1. not more than 60 months after the first test; and

2. thereafter, not more than 10 years after the most recent test.

Comment:

V. The public interest, including the public’s interest in visibility in the Gorge, weighs heavily in favor of 

DEQ carefully considering and resolving the above-mentioned issues.

 

8

See page 24.

9 EPA has used CO as a surrogate for organic HAP. See, for example, the preamble to the National Emission 

Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and 

Process Heaters at 7138 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013. As organic HAP are also 

VOC, DEQ believes CO is a reasonable surrogate for VOC.
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Previously mentioned issues in this permit, unless resolved, have the potential to undermine progress that 

has been made in addressing visibility in the Columbia River Gorge and Mt. Hood pursuant to the Oregon 

Regional Haze Plan. Although DEQ and Columbia River Gorge Commission have taken important steps 

to address visibility degradation in these areas, issues with this permit, unless corrected, would allow TEC 

to impact Class I Areas like Mount Hood, as well as National Scenic areas like the Columbia River 

Gorge, to a greater extent than necessary.

This is problematic in light of federal requirements that visibility should be improved to “natural

conditions” for Class 1 areas by 2064 and that reasonable further progress must be made toward this goal. 

40 C.F.R. § 41.308(d)(1) (2013). Most importantly, though, this is problematic from the standpoint of the 

public’s overall enjoyment of Mount Hood and the Gorge.

This permit’s review report’s discussion of the Air Quality Related Values (AQRV) analysis recognizes 

that, in some cases, visibility and deposition impacts within the Gorge are greater than in Class I Area 

thresholds. TEC Permit Review Report, at 46-47. The review report deflects this by stating that the Gorge 

is not expected to reach ‘natural conditions’ and that these results should be considered concurrently with 

improvements in visibility from emissions reductions from the PGE-Boardman power plant in Oregon 

and the Centralia plant in Washington.

NEDC recognizes that the Gorge is not subject to the federal Regional Haze Program. However, in the 

Columbia River Gorge Air Study and Strategy of 2011, DEQ stated that “[t]he goal for visibility in the 

Gorge is continued improvement using the same approach used in the federal Regional Haze Program.” 

See Columbia River Gorge Air Study and Strategy of 2011, at 6, available at

http://www.deq.state.or.us/aq/gorgeair/docs/11aq035_gorgeAirStudy.pdf (emphasis added). DEQ can 

help ensure that this goal is best met and that the public interest is best served by curing the several issues 

with TEC’s permit, highlighted earlier in this comment. Thank you for your careful consideration of these 

comments.

Response:

Troutdale Energy Center submitted an analysis of the facility’s impacts on the Columbia River Gorge 

National Scenic Area (CRGNSA) which indicated certain impacts greater than what is allowed in Class I 

areas. The analysis was based on reasonable worst-case emissions scenarios. DEQ reviewed the analysis 

and after considering comments by federal agencies such as the U.S. Forest Service concluded the 

following:

“While not “zero”, the low and localized levels of TEC’s visibility and deposition impacts appear 

consistent with the dual goals of the Gorge Air Strategy of protecting and enhancing the scenic, natural, 

cultural and recreational resources as well as protecting and supporting the economy of the Columbia 

Gorge. We acknowledge that visibility improvement cannot be expected to reach ‘natural conditions’ as is 

the case for pristine Class I wilderness areas.”10

None of the emissions scenarios used in the analysis are affected by the commenters’ comments, and 

DEQ does not agree with commenters that “Previously mentioned issues in this permit, unless resolved, 

 

10 Review of the USFS technical analysis of TEC impacts on the Scenic Area, appendix to letter from Andrew 

Ginsburg, DEQ, to Ms. Lynn Burditt, U.S. Dept. of Agriculture-Forest Service, August 16, 2013
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

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Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

have the potential to undermine progress that has been made in addressing visibility in the Columbia 

River Gorge and Mt. Hood pursuant to the Oregon Regional Haze Plan.”

Comments by Richard Till, Friends of the Columbia Gorge

Commenter:

Richard Till, Conservation Legal Advocate

Friends of the Columbia Gorge

rick@gorgefriends.org

Direct: 971-634-2032

General Office: 503-241-3762

Fax: (503) 241-3873

Comment:

Friends of the Columbia Gorge (“Friends”) has reviewed and would like to comment on the Department 

of Environmental Quality’s (“DEQs”) proposed air quality permit (“proposed permit”) for the Troutdale 

Energy Center (“TEC”) and supporting materials that were incorporated by reference. Friends is a nonprofit organization with approximately 5,000 members dedicated to protecting and enhancing the 

resources of the Columbia River Gorge. Our membership includes hundreds of citizens who live, work, 

and recreate in the Columbia River Gorge National Scenic Area (CRGNSA or National Scenic Area). 

Friends is concerned about the potential impacts of the TEC facility on the scenic, natural, recreational, 

and cultural resources of the Columbia River Gorge. This concern is supported by comments that have 

been submitted to the Oregon Energy Facility Siting Council (EFSC) by the Forest Service, the Columbia 

River Gorge Commission, and the National Park Service.1These agencies have concluded that the facility 

would likely cause significant adverse impacts to the National Scenic Area and other significant 

resources, such as the Lewis and Clark National Historic Trail. While DEQ’s Clean Air Act regulations 

do not directly address these concerns, DEQ’s draft permit incorporates voluntary analysis that does 

address these impacts. DEQ should revise these supporting materials to be consistent with the conclusions 

reached by other expert agencies. 

The impacts from the TEC facility implicate several regulatory programs that overlap with DEQ’s federal 

Clean Air Act air quality regulations.2 These comments will address issues related to DEQ’s air quality 

permitting, the Columbia River Gorge Air Quality Strategy that was approved by the Columbia River 

Gorge Commission, and Oregon’s Energy Facility Siting Council (EFSC) regulations that prevent 

significant adverse impacts from air pollution to the Columbia River Gorge National Scenic Area. 

__________

1

Forest Service, Columbia River Gorge Commission, and National Park Service comments are attached 

for reference.

2

Friends also signed onto comments submitted by the Northwest Environmental Defense Center dated 

October 14, 2013. 
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

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Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

The Forest Service performed independent modeling and analysis and concluded that the project would 

contribute to significant adverse impacts to visibility and increase nitrogen deposition in the National 

Scenic Area. The Forest Service concluded that it was likely that the operation of the TEC would conflict 

with EFSC regulations that protect the National Scenic Area and conflict with the Gorge Air Quality 

Strategy. The Gorge Commission submitted comments to EFSC that supported the conclusions reached 

by the Forest Service and recommended that EFSC address these issues. The National Park Service also 

submitted comments to EFSC recommending protection of resources that are important to the Lewis and 

Clark National Historic Trail. To the extent DEQ has authority to provide analysis of impacts relevant to 

EFSC’s permitting authority, DEQ should be supporting the conclusions reached by the Forest Service, 

the Gorge Commission, and the National Park Service. 

A. The Troutdale Energy Center must comply with both the DEQ Clean Air Act standards and EFSC’s 

siting standards. 

The TEC is subject to three overlapping regulatory programs that are overseen by different agencies. The 

DEQ’s air quality permit program implements the federal Clean Air Act and Oregon’s state 

implementation plan. DEQ’s regulations only require that DEQ “encourage” the applicant “to 

demonstrate that these same emission increases or decreases will not cause or contribute to significant 

impairment of visibility on the Columbia River Gorge National Scenic Area (if it is affected by the 

source).”3 Modeling for impacts to the National Scenic Area is voluntary, not mandatory.4 DEQ’s draft 

permit only addresses mandatory elements of Clean Air Act permitting requirements. However, voluntary 

analysis that was included by reference does address impacts to the National Scenic Area. 

Independent of the Clean Air Act requirements, EFSC’s regulations require that EFSC make findings that 

the TEC not cause significant adverse impacts to the National Scenic Area, including impacts from air 

pollution.5 EFSC’s rules explicitly require EFSC consider impacts to visibility beyond the impact 

regulated by DEQ for protection of Class I airsheds. EFSC regulations also require that EFSC protect 

important recreation resources and scenic and aesthetic resources.6 EFSC’s scenic and aesthetic resource 

protection guidelines specifically require protection of resources identified in management plans, such as 

the Scenic Area Management Plan. If EFSC finds that operation of a facility would cause significant 

adverse impacts to the National Scenic Area, then it must review whether the public benefits of the 

facility of the facility outweigh the significant impacts. 

__________

3 OAR 340-225-0070(3)(a). 

4 DEQ Memorandum at 44 (“These voluntary analyses are considered to be made for informational 

purposes.”) 

5 OAR 345-022-0040; OAR 345-021-0010(L)(C). 

6 OAR 345-022-0100; OAR 345-022-0080.
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 27 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Finally, the Columbia River Gorge Commission recently approved a Gorge Air Quality Strategy for the 

NSA. The Gorge Air Quality Strategy was required by the NSA Management Plan, which implements the 

Columbia River Gorge National Scenic Area Act. The Gorge Commission defended the Air Quality 

Strategy in the Oregon Court Appeals, which affirmed the Gorge Commission’s determination that the 

goal of “continued improvement” was consistent with the requirements of the National Scenic Area Act.7

The Gorge Commission submitted comments to EFSC recommending that EFSC’s proposed order 

address how the facility would address the goal of “continued improvement.”8 This mandate gains 

regulatory authority through EFSC’s independent requirement to protect the Scenic Area and scenic 

resources identified in the Management Plan, which incorporates the Gorge Air Quality Strategy. 

The DEQ’s draft permit and related materials include findings and analysis regarding the Clean Air Act 

permitting requirements, but also includes analysis and conclusions related to the Gorge Air Quality 

Strategy and findings that may be relevant to EFSC’s permitting standards. Friends encourages DEQ to 

revise its permitting materials to clarify its findings related to consistency with the Gorge Air Quality 

Strategy. Friends also encourages DEQ to revise its permitting materials to clarify that the Forest Service, 

as the Federal Land Manager, and the Gorge Commission, are the agencies with the relevant expertise for 

identifying thresholds for significant adverse impacts under EFSC’s regulations. 

1. DEQ’s supporting materials should be revised to clarify EFSC’s permitting authority related to impacts

to protected areas. 

__________

7 Friends of the Columbia Gorge v. Columbia River Gorge Comm’n, 257 Or App 197, 202 (2013). 

8 The Columbia River Gorge Commission is given deference to its interpretations of the National 

Scenic Area Act and the Management Plan, which are federal laws. Friends of the Columbia Gorge 

v. Columbia River Gorge Comm’n, 171 P.3d 942, 953 (Or.App. 2007). The DEQ and EFSC, are 

“directed and provided authority to carry out their respective functions and responsibilities in 

accordance with the [Columbia River Gorge] compact executed under ORS 196.150 to 196.165 and 

the Columbia River Gorge National Scenic Area Act.” ORS 196.155. DEQ and EFSC are both 

responsible for ensuring that projects under their jurisdiction comply with any applicable standards 

from National Scenic Area Act and the Management Plan. 
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 28 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

DEQ’s regulations only require that DEQ encourage the applicant to prepare modeling of impacts to the 

National Scenic Area. Accordingly, the applicant volunteered to prepare modeling of impacts to the 

National Scenic Area. DEQ’s proposed permit does not appear to include any conditions that directly 

address potential impacts to the National Scenic Area. The permitting materials do include a Draft Air 

Contaminant Discharge Permit Review Report for the Troutdale Energy Center, LLC.

9 This “Review 

Report” describes the air quality analysis that was prepared by the applicant and a voluntary air quality 

impacts assessment for the National Scenic Area.10 The Review Report states that the applicant’s analysis 

was reviewed and approved in a DEQ memorandum and incorporates that memorandum as an 

attachment.11 The DEQ staff memorandum contains the DEQ’s review of the applicant’s National Scenic 

Area analysis as well as a response to the Forest Service’s comments on that analysis. 12 The staff 

memorandum addresses the Forest Service’s comments regarding the Gorge Air Quality Strategy, but 

is silent on the Forest Service’s comments regarding the TEC’s likely inconsistency with the EFSC’s 

siting guidelines. 

Because the Forest Service is the Federal Land Manager responsible for the affected landscape, DEQ 

should be supporting the Forest Service’s conclusions regarding the likely impacts of the TEC 

facility. Instead, the staff memorandum disagrees with the Forest Service’s analysis and conclusions 

regarding consistency with the Gorge Air Quality Strategy. The staff memorandum states that the 

applicant’s methodologies were “reasonable” based on an excerpt of the Air Quality Strategy that 

states: “There is no scientific justification for selecting one air quality threshold over another as ‘the 

correct’ goal for the Gorge.”13 This excerpt from the Gorge Air Strategy that is taken out of context. 

The next paragraph of the Gorge Air Quality Strategy explains that “[t]he air agencies do not have 

the available funding or staff resources to establish a more prescriptive goal for the Gorge.”14 The

issues identified in the Air Quality Strategy were related to agency capacity for establishing a 

prescriptive goal for the entire Gorge, not the most appropriate methodology for assessing impacts 

from a specific project. 

_________

9 Review Report/Permit No.: 26-0235-ST-01; Application Number: 027060. 

10 Id. at 23, ¶ 43.

11 Id. at 23, ¶ 44. 

12 DEQ Memorandum; Date: 2 August 2013; To: George Davis, From: Svetlana Lazarev, Through: Phil Allen 

Subject: Troutdale Energy Center. 

13 DEQ Staff Memo at 46 (quoting Gorge Air Strategy at 6). 

14 Gorge Air Strategy at 7. 
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 29 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

In the instant case, the Forest Service had the capacity to perform the analysis for the TEC project, 

performed that analysis, and concluded that the project would cause significant adverse impacts. The 

lack of capacity to prepare a Gorge-wide prescription is not a valid basis for dismissing the Forest 

Service’s conclusions for this particular proposal. 

In addition, the Forest Service’s analysis considered the air quality impacts to a small but significant 

portion of the National Scenic Area. The Forest Service expressed concern about impacts from 

nitrogen deposition exceeding thresholds for harm at the Sandy River Delta, which was designated a 

Special Management Area because of its important natural and recreational resources. The Forest 

Service’s more detailed focus and conclusions should not be disregarded because the air quality 

agencies did not have capacity to set Gorge-wide performance criteria. DEQ should revise it staff 

memorandum to acknowledge the validity of the Forest Service’s conclusions. 

The DEQ memorandum acknowledged that, even using the applicant’s modeling thresholds, the TEC 

facility would still exceed those thresholds. The staff memorandum states that “[t]he results . . . show 

visibility and deposition impacts that, in some cases, are greater than the . . . thresholds.”15 Thus, the 

staff memorandum appears to acknowledge that the impacts would exceed a threshold for significant 

impacts. Rather than accept that conclusion, the memorandum immediately dismisses the issue

because Gorge air quality is unlikely to achieve natural conditions that are the goal for Class I 

airsheds.16 The DEQ should revise its analysis to acknowledge that the applicant’s methodology is a 

valid basis for finding significant adverse impacts to portions of the National Scenic Area. While the 

Gorge may not reach “natural conditions,” exceeding thresholds “in some cases” would still 

constitute an adverse impact to protected resources.

2. The DEQ should revise its conclusions regarding consistency with the Gorge Air Quality strategy. 

To the extent DEQ has regulatory obligations under the Gorge Air Quality Strategy, the staff 

memorandum warrants revisions. The Gorge Air Quality Strategy states that “[t]he goal for visibility in 

the Gorge is continued improvement.”17 The Strategy also explains that the Gorge is unlikely to reach 

natural conditions that are the goal for Class I airsheds, but that air quality in the Gorge “can be expected 

to mirror the visibility improvement” that is required to occur in nearby Class I airsheds.18 The staff 

memorandum disagrees with the Forest Service’s conclusion that operation of the TEC facility would be 

inconsistent with the Gorge Air Quality Strategy. 

The DEQ staff memo argues that the TEC project would be consistent with the strategy because of the 

reduction of emissions from two coal-fired power plants.19 The reduction in emissions from the two coalfired plants is completely unrelated to the TEC project and irrelevant to whether the TEC project will 

support or impair the goal of continued improvement in the Gorge. 

__________

15 DEQ Memo at 46 (emphasis added). 

16 Id.

17 Gorge Air Quality Strategy at 6. 

18 Id. 

19 DEQ Memo at 47. 
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 30 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

The improvement to coal-powered plants is also irrelevant to whether the TEC facility would “mirror” 

improvements to Class I airsheds. In reality, the TEC facility is proposed in a uniquely unsuitable location 

for advancing the goals of the Gorge Air Quality Strategy. The TEC facility is proposed adjacent to the 

western gateway to the National Scenic Area, which would likely cause a disproportionate impact to the 

National Scenic Area compared to the likely impacts to Class I airsheds. The Applicant’s modeling, 

which shows acceptable impacts to Class I airsheds but significant impacts in portions of the National 

Scenic Area. Due to the location, the TEC facility would not further the goal of mirroring air quality 

improvements. 

In addition, the goal of continued improvement necessarily implies ongoing improvements to air quality. 

While reductions in emissions from coal-fired plants were a major improvement to visibility in the Gorge, 

those one-time measures will not ensure that there is continued, i.e., on-going improvements to visibility 

in the Gorge. Since coal plant improvements have already occurred, the improvements do not satisfy the 

need for continued improvement beyond implementation of those measures. DEQ should view the 

upgrades to coal-fired power plants as establishing a new baseline from which to measure the next steps 

in continued improvement. The construction of the TEC would undermine continued improvement 

beyond that new baseline. 

Finally, the DEQ’s reasoning essentially argues that TEC project’s air quality impacts will be mitigated

by permitting conditions for the coal-fired power plants. DEQ cannot demonstrate that there will be 

continued improvement by relying on the same mitigation for every new energy facility. While other air 

quality improvement efforts will support continued improvement, a new facility at the mouth of the 

National Scenic Area would impair those efforts and conflict with the goal. 

The Forest Service has commented that the TEC project would conflict with the goal of continued 

improvement. Similarly, the Gorge Commission has recommended that EFSC address the Gorge

Air Quality Strategy through its permitting process. Since the Gorge Commission approved the goal and 

successfully defended that goal in court, DEQ should be acknowledging the agencies conclusions. At the 

very least, the Forest Service’s conclusions should be acknowledged as reasonable. In addition, the DEQ 

should acknowledge the Gorge Commission’s recommendation that EFSC address consistency with the 

Gorge Air Quality Strategy through its siting regulations. 

B. Conclusion 

The Forest Service’s comment to EFSC explained that “it seems probable there may be cases where DEQ 

issues an air quality permit to a proposed new power plant where EFSC may determine not to issue a Site 

Certificate based upon air quality impacts, or vice-versa.” Given this direction, the DEQ should revise its 

staff memorandum to clarify DEQ’s relationship with EFSC’s permitting standards. The DEQ should 

revise its staff memorandum to acknowledge that the Forest Service’s conclusions are reasonable and 

deserving of deference as the Federal Land Manager and agency with responsibility for monitoring air 

quality throughout the Gorge. 

Notably, acknowledging EFSC’s permitting authority does not put EFSC in the position of mandating 

specific pollution control technology that is regulated by DEQ. Instead, this is where EFSC’s balancing 

authority kicks in. EFSC’s regulations require the agency to balance the public benefits of the project 

against any significant adverse impacts to protected areas. If the benefits do not outweigh the impacts, the 

project would be denied. Alternatively, the applicant could modify the project to reduce the impacts to 
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 31 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

ensure compliance with both EFSC standards and DEQ standards. In either case DEQ would retain 

authority to approve the specific pollution control measures employed at the facility. 

In sum, EFSC should revise the supporting materials that were incorporated by reference into the draft 

permit for the TEC facility. Given the complex permitting process and the recommendations of several 

expert agencies, DEQ needs to clarify its findings and conclusions.

Thank you for the opportunity to comment. 

(note: attachment to the Friends of the Columbia Gorge comments are not included here)

Response:

DEQ does not agree that it should revise its conclusions regarding consistency with the Gorge Air Quality 

strategy or that DEQ’s supporting materials should be revised to clarify EFSC’s permitting authority 

related to impacts to protected areas. EFSC’s permitting authority is already defined by rule and further 

clarification by DEQ is not necessary. DEQ’s performed its review of the analysis based on DEQ’s 

applicable rules and regulations. 

Thresholds for evaluating the significance of visibility and other air quality related values (AQRVs) in 

federal Class I areas, which are pristine wilderness areas and national parks, have been long established

by the Environmental Protection Agency and Federal Land Managers, and are used in the PSD program.

Following DEQ guidance, these Class I area thresholds have been used for many years as reference points 

for the Columbia River Gorge, and were considered in TEC’s analysis of impacts in the Gorge. After

review of this analysis, DEQ concluded that TEC’s modeling methods, results, and conclusions were

sound. Based on the data, DEQ concluded that the proposed facility would not cause or contribute to 

significant adverse air quality impacts in the Gorge, or undermine the Gorge air quality strategy, as 

defined in the Columbia River Gorge National Scenic Area Act and the Columbia River Gorge Air 

Quality Strategy.

Regarding the Forest Service review of the TEC Prevention of Significant Deterioration (PSD) modeling, 

DEQ gives great weight to the expertise provided by the USFS in air quality analysis. However, in this 

case, the department respectfully disagrees with some of the conclusions based on significance thresholds 

offered by the Forest Service.

In its evaluation of TEC’s air quality impacts on the Gorge, the USFS relied heavily on the significant 

impact thresholds used for Class I areas. These areas have the most restrictive criteria for defining 

“significant air quality impact” under the PSD rules. The Columbia River Gorge National Scenic Area is 

not a Class I area, but a mixed use area with both scenic and urban characteristics. As noted above, DEQ 

considers the Class I area thresholds as reference points when evaluating air impacts in the Gorge, and 

they can also provide a useful guide when evaluating the effectiveness of Best Available Control 

Technology required by DEQ rules. There is however no basis for requiring the use of Class I thresholds 

as a “standard” that must be met in the Gorge. DEQ is also guided by the definition of “adversely affect” 

as used in the Gorge Scenic Area Act, which defines an adverse impact as a “reasonable likelihood of 

more than a moderate impact,” considering the intensity, magnitude, duration and likehood of the impact, 

as well as other factors. 

The TEC PSD analysis showed that the proposed facility would have a minor impact on air quality at the 

very western edge of the Gorge, during very limited hours, and only under intermittent “worse-case”
DEQ Response to Comments – Troutdale Energy Center

File No. 26-0235

March 5, 2014

Page 32 of 32

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

operating conditions. Based on both the original TEC analysis and the review and re-analysis by the 

USFS, DEQ concludes that the proposed facility would not significantly worsen air quality or degrade 

natural resources in the Gorge, and would not undermine the overall strategy for visibility improvement in 

the Gorge. 

DEQ recognizes the special nature of the Gorge scenic area, and also that the National Scenic Area Act 

reflects the dual nature of the Gorge Scenic Area by establishing protection goals for both valued 

resources and local rural/urban economies in the Gorge. The Columbia River Gorge Air Quality Strategy 

does not impose a ban on growth or the development of new industries in and around the Gorge. In the 

coming years, increases in emissions and air pollution will likely occur as a result of growth in

population, motor vehicle use, economic development, and other local, regional, and international 

activities. However, those emission increases will be offset by emission reductions from a wide variety of 

sources through state and federal regulations, including those adopted under the regional haze program. 

These reductions include cleaner motor vehicle and truck standards, cleaner fuels, and adding pollution 

controls to older industrial facilities such as the Boardman and Centralia coal-fired power plants. As a 

result, Class I areas and the Columbia River Gorge NSA are expected to see a sustained, net improvement

in air quality. Similar to the regional haze program, the goal for visibility in the Gorge is continued 

improvement over time. That means tracking the net change in air quality over time (increases and 

decreases) and ensuring sustained improvement. DEQ will evaluate the progress of this strategy for both 

Class I areas and the Columbia Gorge under its 2014 and 2018 regional haze plan work. 

_______________

doc name: 26-0235-RTC-03052014.docx, March 5, 2014
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 1 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

The draft permit for the Troutdale Energy Center was placed on public notice from September 4, 2013, 

through October 14, 2013. DEQ held a public hearing on October 3, 2013. A total of 181 individuals and 

organizations submitted comments during the comment period.

Public involvement is an important part of the permit issuance process, and DEQ thanks everyone who 

commented for their involvement in the process and for their time and effort.

The comments are organized into six sections in this document, followed by DEQ’s response to the 

comments. The individuals or organizations that submitted the comments are listed in the appropriate 

section.

DEQ issued the proposed permit to Troutdale Energy Center on March 5, 2014. DEQ made the following 

changes to the permit in response to comments:

 Condition 30 was revised to allow use of Ultra Low Sulfur Diesel (ULSD) for maintenance and 

testing, and to otherwise limit usage in all turbines to periods of curtailment. A definition of 

curtailment was also added. See response to comments beginning on page 15.

 Condition 31 was revised to match the monitoring requirements to the revisions to condition 30.

 Condition 44 was revised to refer to 40 CFR Part 60 Subpart KKKK or TTTT, whichever is 

applicable, instead of Subpart TTTT, and to be applicable to all turbines if the final rule affects all 

turbines. See response to comments beginning on page 27.

 Conditions 50 and 51 were revised to increase the amount of emissions testing of the turbines for 

VOC and PM. See response to comments beginning on page 28.

In addition, the following correction was made:

In condition 1 the word “construct” was replaced with “construct and operate”. This permit was intended 

to allow both construction and operation of the facility, but DEQ inadvertently omitted the words “and 

operate” from condition 1 in the draft permit.

Other minor typographical corrections were made when found. Such corrections did not change the 

requirements of the permit.
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 2 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Contents

Comments by 177 individuals .......................................................................................................................................3

Comments by Darryl Usher.........................................................................................................................................11

Comments by Paul Wilcox ..........................................................................................................................................11

Comments by Allen Johnson, Interlachen Inc. ............................................................................................................12

Comments by NEDC, Friends of the Columbia Gorge and Columbia Riverkeeper....................................................15

Comments by Richard Till, Friends of the Columbia Gorge .......................................................................................32
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 3 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Comments by 177 individuals

Commenters:

Submitted by 177 commenters who are listed beginning on page 4.

Summary of comments:

Deny the Troutdale Energy Center.

The facility is in a bad location near the Columbia River Gorge National Scenic Area would harm the 

Columbia River Gorge.

The facility would release air pollution directly into the Columbia River Gorge, which is already suffering 

from poor air quality

The facility would undermine the purposes of the National Scenic Area Act by harming views from 

numerous key viewing areas.

The facility would harm businesses in the Gorge.

Adopt findings that the facility would cause significant adverse impacts to protected areas and recreation 

sites and that energy from the facility is not needed.

Response:

DEQ does not have the authority to deny permits without legal cause, such as inability to comply with the 

applicable permitting requirements. Troutdale Energy Center has complied with the applicable permitting 

requirements.

DEQ recognizes that the proposed facility is located near the Columbia River Gorge National Scenic 

Area. The applicant has provided information that shows that the facility’s impacts are below levels that 

DEQ considers acceptable for this area. DEQ therefore does not agree that the proposed facility would 

undermine the purposes of the National Scenic Area Act by harming views from numerous key viewing 

areas; would adversely affect recreation sites and resources; would harm businesses in the Gorge; or 

would cause significant adverse impacts to protected areas and recreation sites.

DEQ does not regulate energy production and cannot make findings that the energy from the facility is 

not needed.
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 4 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Ms. Steel

General Delivery

Sandy, OR 97055-9999

Mr. A Michael Dianich

42740 E Larch Mt Rd

Corbett, OR 97019-8774

(503) 695-5385

Ms. Alea Kent

810 Cambridge St

Ashland, OR 97520-1008

Ms. Alex Prentiss

15685 SW 116th Ave

King City, OR 97224-2651

Ms. Alice West

1237 SE 53rd Ave

Portland, OR 97215-2646

Ms. Amy Houchen

2419 SW Richardson St

Portland, OR 97239-2133

Mr. and Mrs John & Polly 

Wood

PO Box

Hood River, OR 97031

note: address incomplete

Ms. Ann Watters

1940 Breyman St NE

Salem, OR 97301-4352

Ms. Aria Jackson

2030 NE Hancock St

Portland, OR 97212-4566

Mr. Arland Swanson

9606 26th Ave NW

Seattle, WA 98117-2515

Dr. Barbara Manildi

3525 Red Cedar Way

Lake Oswego, OR 97035-3523

(503) 635-4878

Mr. Benjamin Ignatowski

PO Box 11807

Portland, OR 97211-0807

(503) 284-6717

Ms. Beth Flake

25 Eugene St

Hood River, OR 97031-2215

Dr. Beth Wilmot

11841 SW 60th Ave

Portland, OR 97219-7003

(503) 449-0035

Ms. Bev Hedin

1720 SW 4th Ave Apt 416

Portland, OR 97201-5533

(909) 241-9930

Mr. Billy Don Robinson

1524 NE Hancock St

Portland, OR 97212-4472

(503) 515-1708

Mr. Bob Welsh

2183 Juneau Ct S

Salem, OR 97302-2221

Ms. Carole Beauclerk

1500 SW Park Ave

Portland, OR 97201-3445

(541) 852-9255

Ms. Carolyn Boatsman

3210 74th Ave SE

Mercer Island, WA 98040-3419

(206) 236-0949

Mr. CharlesBetty BrasherLavis

7709 NE 57th Cir

Vancouver, WA 98662-6239

Ms. Cheryl Wagner

20035 SE 27th Pl

Sammamish, WA 98075-9694

Ms. Colleen Wright

4160 Chapman Way

Lake Oswego, OR 97035-5565

(503) 908-1757

Ms. Corinne McWilliams

6325 NE Lessard Rd

Camas, WA 98607-8948

Ms. Daisy Franzini

PO Box 80248

Portland, OR 97280-1248

Mr. Dan Lamberger

1441 SW Clay St Apt 107

Portland, OR 97201-6044

(503) 274-9956

Mr. Dan Sherwood

1719 SE 35th Ave

Portland, OR 97214-5038

Dr. Daniel Jaffee
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 5 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

4723 NE 14th Ave

Portland, OR 97211-5011

Mr. Dave King

8728 N Edison St

Portland, OR 97203-5316

Mr. David Williams

3049 SW 32nd Ter

Gresham, OR 97080-8482

Ms. Dawn Smallman

1148 SE 50th Ave

Portland, OR 97215-2606

Ms. Debra Rehn

5230 SE 30th Av. Apt. 9

Portland, OR 97202

Dr. Delton Young

7731 21st Ave NE

Seattle, WA 98115-4503

(206) 522-9535

Mr. Derek Gendvil

9030 W Sahara Ave # 360

Las Vegas, NV 89117-5744

Mr. Dermot Noonan

4510 48th Ave NE

Seattle, WA 98105-3824

Ms. Diana Moeller

1918 Harris Ave

Richland, WA 99354-2340

Ms. Diane Enochson

9921 N Ivanhoe St

Portland, OR 97203-1419

Ms. Dinda Evans

PO Box 178695

San Diego, CA 92177-8695

Mr. Donald Springer

8321 NE 54th St

Vancouver, WA 98662-6085

Ms. Donna Crane

1576 Beebe Ln

Eugene, OR 97404-2906

(541) 607-7330

Mr. Doug Richardson

2020 SW Main St Unit 801

Portland, OR 97205-1535

(503) 224-0756

Mr. Duff Linde

37713 SE 35th St

Washougal, WA 98671-6775

(360) 798-2804

Mrs. Erika Markel

24495 Butteville Rd NE

Aurora, OR 97002-9666

Ms. Evy Bishop

13932 NE Beech St

Portland, OR 97230-2738

Ms. Frances Hannah

14700 SE 33rd Way Apt 164

Vancouver, WA 98683-9227

Dr. Fredrick Seil

1 Twain Ave

Berkeley, CA 94708-1734

Mr. George Cummings

3816 NE 17th Ave

Portland, OR 97212-1335

(503) 288-2361

Dr. George Pantely

5276 Quinn Dr

Mount Hood Parkdale, OR 

97041-7633

(541) 352-5550

Ms. Gloria McCracken

PO Box 810

Chiloquin, OR 97624-0810

Mr. Gradey Proctor

6003 SE Milwaukie Ave

Portland, OR 97202-5344

Mr. Grant Fujii

5906 N Depauw St

Portland, OR 97203-5116

Mr. Ian Shelley

50 SW 97th Ave

Portland, OR 97225-6902

Mr. Jack West

3914 SE Licyntra Ln

Milwaukie, OR 97222-8835

Mr. James Gilmore

3532 N Missouri Ave

Portland, OR 97227-1167

(503) 249-5170

Ms. Jan McCreary

PO Box 3042

Silver City, NM 88062-3042
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 6 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Ms. Jan Polychronis

PO Box 639

The Dalles, OR 97058-0639

Ms. Jane Harold

1515 SW Pendleton St

Portland, OR 97239-2617

Ms. Jane Hillemann

PO Box 1600

Vancouver, WA 98668-1600

(360) 696-5094

Mr. Jay Humphrey

25525 S Laura Ln

Estacada, OR 97023-9417

Mr. Jay Russo

1262 Duncan Creek Rd

Stevenson, WA 98648-6177

Mrs. Jennifer Musgrave

8417 N Princeton St

Portland, OR 97203-4845

(503) 349-5623

Ms. Jessi Snow

4304 SE 103rd Ave

Portland, OR 97266-2426

Mr. Jim Clarkson

86083 Cherokee Dr

Eugene, OR 97402-9039

Mr. Jim Gilbert

28696 S Cramer Rd

Molalla, OR 97038-8576

(503) 651-2463

Ms. Joana Kirchhoff

3414 NE 73rd Ave

Portland, OR 97213-5826

(503) 280-9880

Dr. Joel Kay

10707 SE Stanley Ave

Milwaukie, OR 97222-4362

(503) 654-5567

Mr. Joel Rosenblit

2208 Joplin Ct S

Salem, OR 97302-2217

Mr. John Knipe

1071 S Juniper St

Rockaway Beach, OR 97136-

9726

Mr. John Morris

6636 SW Burlingame Ave

Portland, OR 97239-2640

Mr. John Nettleton

4311 SE 37th Ave Apt 21

Portland, OR 97202-3265

(971) 207-1142

Mr. John Reynolds

12737 SE 25th Ave

Milwaukie, OR 97222-7938

Mr. John Ritter

109 Montello Ave

Hood River, OR 97031-2235

(541) 806-2680

Mr. John Wadsworth

9271 SW 3rd Ave

Portland, OR 97219-4811

(503) 478-0667

Ms. Joni Zimmerman

1101 W Sheridan St

Newberg, OR 97132-6846

Mr. Joshua Glover

716 Oak St Apt 6

Hood River, OR 97031-1879

(503) 560-3653

Ms. Joy Gohl

725 Snowden Rd

White Salmon, WA 98672-8224

Mrs. Judy Anderson

74015 cougar mt. Rd.

Cottage grove, OR 97424-9234

Ms. Judy Todd

1631 NE Broadway St

# 723

Portland, OR 97232-1425

(503) 260-4995

Ms. Kara Ford

3444 SE Grant St

Portland, OR 97214-5732

(503) 833-2290

Ms. Kathleen Jones

2015 Crest Dr.

Lake Oswego, OR 97034

Ms. Kathryn Elich

10607 E Burnside St Apt 63

Portland, OR 97216-2783

(503) 935-4161
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 7 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Mrs. Krista Reynolds

1536 NE Saratoga St

Portland, OR 97211-4728

Ms. Laura Hanks

7634 SE Alder St

Portland, OR 97215-2312

Mrs. Laurel Turner

11333 SE Powell Ct

Portland, OR 97266-1758

(503) 760-7400

Mr. Lawrence Nagel

375 Ashland Loop Rd

Ashland, OR 97520-2803

Mr. Leslie Burpo

PO Box 5468

Eugene, OR 97405-0468

(541) 338-7099

Dr. Lester Baskin

2222 NW Lovejoy St Ste 406

Portland, OR 97210-5108

(503) 808-9211

Mrs. Linda Browning

000 0000000 000000

Beaverton, OR 97008

note: address not given

Mrs. Luanne Mierow

26040 S Jewell Rd

Beavercreek, OR 97004-9746

(503) 632-6409

Ms. Lydia Deems

241 Lakeside Dr

White Salmon, WA 98672-9006

Ms. Lynda Cunningham

5505 E Evergreen

Vancouver, WA 98661

Mrs. Lynn Putnam

2368 NW 6th St

Bend, OR 97701-1188

Ms. Marcia Tate

6110 NE 53rd Pl

Portland, OR 97218-2379

Ms. Margaret Keene

97503

White City, OR 97503

note: address incomplete

Ms. Maria White

18880 SW Hart Rd

Beaverton, OR 97007-5623

Ms. Marianne Lawrence

20098 SW Squire Dr

Beaverton, OR 97007-7498

Ms. Marlene Elliott

6105 Bonita Rd Apt K206

Lake Oswego, OR 97035-2243

(503) 484-8146

Mrs. Martha Eslinger

5383 Howell Prairie Rd NE

Silverton, OR 97381-9358

Ms. Martha Stevenson

PO Box 1878

White Salmon, WA 98672-1878

(509) 493-9261

Ms. Mary Bailey

595 NW Lost Springs Ter Unit 

404

Portland, OR 97229-6589

(503) 944-9411

Dr. Mary Blankevoort

31320 NE Hurt Rd

Troutdale, OR 97060-9383

Ms. Mary Grout

9137 NW McKenna Dr

Portland, OR 97229-8039

(503) 292-5440

Ms. Mauria McClay

1005 SE 14th Ave

Portland, OR 97214-2546

Ms. Melba Dlugonski

6735 SE 78th Ave

Portland, OR 97206-7116

Ms. Meryle A. Korn

5256 NE 47th Ave

Portland, OR 97218-1966

(503) 281-7475

Mr. Michael Fierst

2811 NE 92nd Ave

Portland, OR 97220-5366

Ms. Monica Gilman

25525 S Laura Ln

Estacada, OR 97023-9417

Ms. Nancy Platner

2150 Elder Rd

Hood River, OR 97031-8534
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 8 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Mrs. Nicole Sibert-Faaborg

1635 5th St

Hood River, OR 97031-6724

Mr. Norm Enfield

2615 NW 46th Cir

Camas, WA 98607-9141

Ms. Patricia March

723 Lafayette Ave

Columbus, IN 47201-6268

(812) 372-7245

Ms. Patricia Orlinski

10511 W Kingswood Cir

Sun City, AZ 85351-2246

(623) 876-1525

Dr. Paul Metzger

5105 SW Evelyn St

Portland, OR 97219-5869

Dr. Paul Meyer-Strom

4723 SW 50th Ave

Portland, OR 97221-3020

Dr. Paul Torrence

1455 Woodland Dr

Ashland, OR 97520-3451

(541) 708-0153

Ms. Paula Muellner

PO Box 211

Arlington, OR 97812-0211

Mrs. Paula Taccogna

16799 SE Kingsridge Ct

Milwaukie, OR 97267-5247

(503) 513-4951

Mr. Peter von Christierson

1229 - 29thSt.

Port Townsend, WA 98368

Ms. Polly Wood

PO Box 962

Hood River, OR 97031-0032

Ms. Rachel Jordan

285 E 36th Ave

Eugene, OR 97405-4747

(541) 484-9342

Ms. Regna Merritt

260 NW Pittock Dr

Portland, OR 97210-1075

Mr. Richard Schramm

3024 NE Bryce St

Portland, OR 97212-1718

(503) 288-8912

Mrs. Rick Reynolds

1536 NE Saratoga St

Portland, OR 97211-4728

Mr. Rik Masterson

4542 NE 27th Ave

Portland, OR 97211-6524

Mr. Robert and Dolores 

Scheelen

123 Sunrise Ave

Medford, OR 97504-7022

Dr. Ron & Paulette Tatum

17435 SW Blanton St

Aloha, OR 97007-1340

(503) 848-9537

Dr. Ronald Jr

1401 Cross Creek Ln

Hood River, OR 97031-1370

(541) 234-4528

Mr. Ryan Rittenhouse

4806 SE 28th Ave

Apt 719

Portland, OR 97202-4491

(440) 796-9695

Mr. Ryan Wishart

54 N Adams St

Eugene, OR 97402-4274

Dr. Sally Behel

11747 SW Military Ln

Portland, OR 97219-8434

Dr. Sandra Joos

4259 SW Patrick Pl

Portland, OR 97239-7202

(503) 274-8803

Ms. Sandra Williams

2804 SE 27th Ave

Portland, OR 97202-1397

(503) 232-7337

Ms. Sarah Hafer

1401 Wyant Way

Sacramento, CA 95864-2639

(916) 384-9551

Ms. Sharilyn Cohn

128 NE 43rd Ave

Portland, OR 97213-1604
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 9 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Ms. Sharon Lee

2277 NE Baron Ct

Bend, OR 97701-6606

Ms. Shawn Looney

12937 NW Newberry Rd

Portland, OR 97231-2210

(503) 735-9268

Dr. Stephen Bachhuber

10561 SE Idleman Rd

Happy Valley, OR 97086-6914

(503) 777-8608

Mr. Stephen Gerould

3307 SW Dosch Rd

Portland, OR 97239-1423

(503) 221-7253

Mr. Steven Wheeler

5332 NE Broadway St

Portland, OR 97213-2761

Ms. Susan Bissell

2913 NE 29th Ave

Portland, OR 97212-3558

(503) 477-8118

Ms. Susan Dornfeld

PO Box 8305

Portland, OR 97207-8305

Mrs. Susan Hartford

3580 Thomsen Rd

Hood River, OR 97031-8404

Mrs. Sybil Kohl

18103 NE 159th Ave

Brush Prairie, WA 98606-8738

(360) 666-1313

Mr. Ted Light

612 SE 48th Ave

Portland, OR 97215-1721

(503) 445-7643

Ms. Teri Landauer

PO Box 123

Alsea, OR 97324-0123

Mr. Thomas Lange

5420 SW Idaho St

Portland, OR 97221-1621

Mr. Timothy Ulrey

4741 SE 34th Ave

Portland, OR 97202-3315

(503) 771-8303

Mr. William O'Brien

12520 SW Gem Ln Apt 202

Beaverton, OR 97005-1360

Dr. William Whitaker

1108 G Ave

La Grande, OR 97850-2035

Dr. Richard Gorringe, Ph. D.

3574 NE Stanton St

Portland, OR 97212-2747

Dr. Eric Brentlinger

4160 Post Canyon Dr

Hood River, OR 97031-7726

Dr. Edward McAninch

1820 NW Edgehill St

Camas, WA 98607-9364

Ms. Jeanette Ruff

1378 105th Ln NW

Coon Rapids, MN 55433-4889

(503) 927-2874

Mr. Joe Walicki

14760 SW Wheaton Ln

Beaverton, OR 97007-3690

Mr. John Goeckermann

Hugo Road

Grants Pass, OR 97528

note: address incomplete

Mr. Jonathan and Ms. Deanne 

Ater

3344 SW Fairmount Ln

Portland, OR 97239-1446

Ms. Judith Nappe

PO Box 531

North Bonneville, WA 98639-

0531

Mrs. Judy Zettergren, Ph.D.

2693 NW Pinot Noir Dr

Mcminnville, OR 97128-2058

Ms. Juliann a Guy

4559 El Dorado Way

Bellingham, WA 98226-1221

(360) 738-8466

Ms. Karen Grimstad

41025 SE Washougal River Rd

Washougal, WA 98671-5872

Ms. Kate Schmitt

PO Box 29083

Portland, OR 97296-9083

Ms. Kathryn Elich
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 10 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

10607 E Burnside St Apt 63

Portland, OR 97216-2783

(503) 935-4161

Mr. Keith Dunbar

14310 93rd Ave NE

Kirkland, WA 98034-5148

(425) 820-5750

Ms. Laurie E. Milford

1840 Orchard Rd

Hood River, OR 97031-9694

Lee and Cheryl Siebert

1524 SW Miller Ct

Gresham, OR 97080-9358

Ms. Marjorie Johnson

640 NW Freeman Ave

Hillsboro, OR 97124-2833

(503) 640-4682

Mr. Martin McGinn

2719 SE 48th Ave

Portland, OR 97206-1518

(503) 231-0504

Ms. Mary Hayden

18347 S Redland Rd

Oregon City, OR 97045-8063

(503) 631-7040

Mr. Michael Parker

PO Box 65

Oysterville, WA 98641-0065

(360) 665-5077

Patricia Richardson

59051 Elizabeth Lane

St Helens, Or 97051

Robbie Moller

425 Eugene Ave.

Hood River, OR 97031

Ms. Susan O'Hara

PO Box 87575

Vancouver, WA 98687-7575

(360) 604-1205

Mr. Steven Amick

23360 S Viola Welch Rd

Beavercreek, OR 97004-9714

Mrs. Lisa Nelski

12306 NE 11th Cir

Vancouver, WA 98684-5869

(360) 449-9897

Ms. Kyenne Williams

2833 N Terry St

Portland, OR 97217-6253

(503) 239-0058

Mr. Chris Carvalho

17717 SW Washington Dr

Aloha, OR 97007-1748

(503) 642-3199

Mr. Jake Culver

1 Main St.

Portland, OR 97202

Dr. Jim Haynes

22 Montello Ave

Hood River, OR 97031-2234

(541) 386-4934
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 11 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Comments by Darryl Usher

Commenter:

Mr. Darryl Usher

9810 NW Gordon Rd

Cornelius, OR 97113-6314

Comment:

I encourage you pass the Troutdale Energy Facility, proposed at the Gateway to the Columbia Gorge.

Response:

Thank you for your comment.

Comments by Paul Wilcox

Commenter:

Paul Wilcox

1030 SW 17th Way

Troutdale, OR 97060

Summary of comments:

The applicant has chosen the monetary path to offset CO2 emissions and will pass the cost on to 

customers; the result is higher rates and more pollution.

The diesel fuel storage capacity of 2.2 million gallons seems excessive.

If air quality in the Portland Metro area is of sufficient concern as to require vehicle smog testing, why 

introduce such a massive single source of pollution into a heavily populated area?

There is no demonstrated need for the excess generating capacity this facility would provide.

Response:

The Oregon Department of Energy administers the CO2 emissions offset program and the Public Utility 

Commission regulates utility costs. DEQ has no role in either the CO2 emissions offset program or the 

regulation of utility costs.
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 12 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

DEQ does not regulate the size of fuel storage tanks. However, DEQ has estimated that 2.2 million 

gallons of diesel (ULSD) equates to roughly 82 hours of operation at the maximum operating rate for all 

turbines. The DEQ permit allows operation on ULSD fuel up to 720 hours per year per turbine.

DEQ is responsible for ensuring that air quality in the entire state meets National Ambient Air Quality 

Standards. Air quality in the Portland Metro area currently meets all National Ambient Air Quality 

Standards but this has not always been the case and extra measures, such as vehicle smog testing, were 

instituted to help air quality meet the ambient air quality standards. DEQ operates the vehicle smog 

testing program in Portland in combination with the industrial source permitting program to help ensure 

that air quality will continue to meet National Ambient Air Quality Standards. As part of the permit 

application, Troutdale Energy Center was required to assess the potential impact of their emissions on the 

air shed’s ability to meet ambient air quality standards. DEQ reviewed that analysis and has determined 

that Troutdale Energy Center successfully demonstrated that emissions from the proposed facility will not 

significantly affect air quality in the Portland Metro area. DEQ also notes that Troutdale Energy Center 

must meet stringent Best Available Control Technology limits that serve to minimize emissions from the 

facility.

DEQ does not regulate energy production and cannot make findings related to generating capacity.

Comments by Allen Johnson, Interlachen Inc.

Commenter:

Allen O. Johnson

President, Interlachen Inc

P.O. Box 96

Fairview, OR 97024

503 512 8222

Comments:

1. Interlachen has its own water district, the Interlachen Water Public Utility District. The Notice of 

Intent mentions the estimated use of 5.3 million gallons of water per day. It says most of it will be 

supplied by the City WPCF, City of Troutdale and Port of Portland. Additionally, it mentions 

applications for water rights for new wells. We are naturally concerned that the aquifer can support the 

additional demand, and request that the impact on the aquifer be explored. 
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 13 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

2. Blue Lake gets its water from a shallower aquifer that is influenced by the Columbia River. When the 

river is low, Blue Lake Residents pay for water fills from the Port of Portland wells to keep Blue Lake's 

water level suitable for recreational purposes. This cost is between one and two thousand dollars per fill 

depending on the amount of water required. If the Troutdale Energy Center is also drawing from this 

aquifer, the residents of Blue Lake may be forced to pay thousands of dollars for additional fills to 

maintain the lake. We would like the impact on Blue Lake, and the recreation at Blue Lake Park, 

considered in the assessment. 

3. Power Lines were constructed to support the Reynolds Aluminum plant that was located near the 

proposed site of the Troutdale Energy Center. These lines were never put into use, as the Reynolds 

facility was closed before they were activated. These lines run right through Interlachen and Fairview 

Lake Property Owners Association properties. The Notice of Intent describes the installation of lines to 

the PGE, PP&L, and one other substation. While connection to the overhead transmission towers is not 

within the scope of this Notice of Intent, we are wondering if connection to the power grid includes plans 

to activate these lines? 

4. Blue and Fairview Lake communities are somewhat isolated from general traffic flow patters, and as 

such we live in a very quiet and peaceful community. We have the occasional train noise and aircraft 

noise from the Troutdale airport. We would like to know what the audible levels of the plant will be? 

Will we hear the constant whine of turbines two miles away? What is the audible levels of the facility at 

certain distances? 

5. Lastly, we would like to know the impact of the combustion process air discharges. 40 tons of NOx 

doesn't mean much to John Doe. How does that equate to the discharges from trucks passing by on I-84 

or jets taking off from PDX? In other words, does this equal the emissions from 600 trucks a day passing 

through our neighborhood? 

Response:

Comments 1 through 3 are outside the scope of the air quality permitting program.

Regarding comment 4, audible noise levels, DEQ’s noise program was terminated in 1991 along with 

funding to administer and enforce the noise regulations. However, the Proposed Order for the Troutdale 

Energy Center issued by the Oregon Department of Energy and dated December 16, 2013 addresses noise 

issues in several locations in the proposed order. The proposed order (at least as of February 5, 2014) is 

available at:

http://www.oregon.gov/energy/Siting/docs/TEC/TEC_proposed_order_121613.pdf
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 14 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Regarding comment 5, the daily amount of emissions from Troutdale Energy Center might be equivalent 

to the amount of emissions from several hundred trucks, but the pollution effects of Troutdale Energy 

Center and several hundred trucks per day passing through the neighborhood would be quite different.

Emissions from trucks passing through the neighborhood would occur in close proximity to residents. 

While DEQ has not performed a detailed analysis of the effect this would have, it is likely that pollutant 

levels would build up locally and some air quality standards may be exceeded. For example, a 1-hour 

ambient air quality standard for nitrogen dioxide (NO2) was established in recent years by the U.S. 

Environmental Protection Agency (EPA) and it is generally believed by both EPA and DEQ that the most 

likely locations for this standard to be exceeded are near heavily travelled highways.

Regarding the effects of Troutdale Energy Center’s emissions, DEQ required Troutdale Energy Center to 

perform a modeling analysis of the facility’s emissions. DEQ reviewed and approved the analysis results 

and methodology.

The analysis looked at attainment with the National Ambient Air Quality Standards considering all 

sources of air pollution, and the contribution of emissions from Troutdale Energy Center compared to 

Significant Impact Levels. The analysis indicates that emissions from the facility will comply with 

Oregon’s regulations for the protection of air quality and in general will not cause air quality to exceed 

any National Ambient Air Quality Standards. The modeling did show exceedances of the 1-hour NO2

National Ambient Air Quality Standard at five locations. At four of those locations, the contributions 

from the Troutdale Energy Center were very low and not considered significant, while at the fifth location 

(near the paper mill in Camas, Washington) the contribution was higher but still below a level considered 

significant. In other words, the modeled exceedances of the 1-hour NO2 National Ambient Air Quality 

Standard are mainly the result of other emissions sources and Troutdale Energy Centers’ contributions to 

the exceedances were below significant impact levels.

The modeling review, which contains the results of this assessment is attached to the review report for the

permit and is available from DEQ.
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 15 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

Comments by NEDC, Friends of the Columbia Gorge and Columbia Riverkeeper

Commenters:

Air Quality Group, Northwest Environmental Defense Center

JJ England

Shanna Fricklas

Matthew Ring

Heather Fossity

Rachel Morris

YoungWoo Joh

Erica Nist-Lund

Friends of the Columbia Gorge

Columbia Riverkeeper

Comment:

II.A. Unrestricted permission to use ultra low sulfur distillate fuel 720 hours/year, without specifying this 

as solely a backup fuel for EU2/EU3, does not constitute BACT.

This ACDP’s review report explains that “[t]he two simple-cycle combustion turbines [EU2/EU3] may 

burn ULSD at any time, with each limited to 720 hours per year.” TEC Permit Review Report, at 5. This 

is as compared to the combined cycle turbine, EU1, which is only permitted to burn ULSD during periods 

of natural gas curtailment. Permitting EU2/EU3 to combust ULSD in any capacity other than as a backup 

fuel or during periods of natural gas curtailment does not meet the requirement for BACT for NOx, CO, 

or VOC. For this permit to meet the requirement of BACT, it must require combustion of the cleanest 

burning fuel (natural gas) at all times except when backup fuel must be used (e.g., due to natural gas 

curtailment), at which time the cleanest burning backup fuel (ULSD) must be used. This approach yields 

the best control technology, accounting for the project’s purpose, feasibility, economic, and other impacts. 

The permit does not make this distinction, resulting in a flawed top-down BACT analysis.

Response:

In the draft permit, DEQ did not propose to limit the hours of operation on ULSD as part of the BACT 

determination. DEQ did include limits on the hours of operation on ULSD as an “Owner requested 

limitation” under the authority of OAR 340-226-0120(1), Operating and Maintenance Requirements.

"Best Available Control Technology" or "BACT" is defined in Oregon Administrative Rule 340-200-

0020(15) as follows:
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 16 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

(15) "Best Available Control Technology" or "BACT" means an emission limitation, including, 

but not limited to, a visible emission standard, based on the maximum degree of reduction of each 

air contaminant subject to regulation under the Act which would be emitted from any proposed 

major source or major modification which, on a case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, is achievable for such source or 

modification through application of production processes or available methods, systems, and 

techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for 

control of such air contaminant. In no event may the application of BACT result in emissions of 

any air contaminant that would exceed the emissions allowed by any applicable new source 

performance standard or any standard for hazardous air pollutant. If an emission limitation is not 

feasible, a design, equipment, work practice, or operational standard, or combination thereof, may 

be required. Such standard must, to the degree possible, set forth the emission reduction 

achievable and provide for compliance by prescribing appropriate permit conditions.

DEQ’s BACT determination established emission limitations for the turbines for both fuel types, with the 

exception of GHGs where a single limitation covers both fuels. Although multiple BACT limitations for a 

single device and pollutant are sometimes specified by permitting authorities, DEQ notes that the 

definition of BACT does not require multiple limitations. DEQ’s BACT determination therefore meets 

the definition of BACT as it stands and is not deficient.

However, DEQ agrees with the concept of further limiting the use of ULSD to the extent reasonably 

possible given the nature of the facility, and in consideration of comments received, reviewed condition 

30.

Condition 30 in the draft permit stated that the combustion turbines must burn only natural gas except as 

follows:

 The combined cycle combustion turbine (EU1) may burn ULSD fuel in the event of natural gas 

curtailment, not to exceed 720 hours per calendar year. (emphasis added)

 The simple cycle combustion turbines (EU2 and EU3) may burn ULSD fuel, not to exceed 720 

hours per turbine per calendar year.

In reviewing this condition, DEQ first made an effort to better understand the meaning of “natural gas 

curtailment”. Oregon law provides that certain government entities, such as the Public Utility 

Commission (PUC), may curtail natural gas in the event of an emergency. PUC regulations also require 

natural gas utilities to prepare plans for the curtailment of natural gas deliveries in the event of a situation 

that threatens the long-term deliverability of natural gas. DEQ contacted Northwest Natural Gas to 

discuss curtailments and learned that the utility may curtail gas deliveries when local demand exceeds the 
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

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503-229-5534

utility’s ability to supply gas. This usually occurs during extreme cold weather and in a limited 

geographic area. Curtailment is implemented through rate schedules that effectively establish gas user 

priorities. Firm price customers have top priority, and this category includes residential customers. Large 

industrial customers that can use a backup fuel often choose to be on an interruptible rate schedule, which 

includes a significant cost penalty if the customer continues to use natural gas after being ordered to 

curtail the use of gas. If gas demand exceeds the ability to supply, interruptible customers in the affected 

area are contacted and told to curtail the use of gas. Curtailment is not effected by physically shutting off 

the flow of gas, but by the price penalty in the interruptible rate schedule.1

DEQ requested Troutdale Energy Center clarify their intentions with respect to the use of ULSD fuel. 

Troutdale Energy Center provided the following information on December 23, 2013:

“Troutdale Energy Center, LLC (TEC) has requested the ability to use ULSD instead of natural 

gas at its proposed combustion turbine facility in Troutdale, OR (the Facility) during actual or 

effective deliverability events related to either natural gas commodity supply or transportation 

curtailment. Natural gas delivered to the Facility will be sourced from Canada, the Rocky 

Mountains and the San Juan natural gas basins from the Williams’ Northwest Pipeline. The 

Northwest Pipeline is a 3,900-mile bi-directional gas transmission system crossing the states of 

Washington, Oregon, Idaho, Wyoming, Utah and Colorado. During periods of high demand 

(typically cold temperatures in Canada, the Rocky Mountain region and/or the Four Corners 

region of the southwest US), natural gas prices can exhibit extreme price volatility that make it 

infeasible to use. During periods of high demand Williams may also curtail transportation rights 

along the over-subscribed Northwest Pipeline and limit transportation to Local Distribution 

Companies that serve higher priority residential customers. In the case of extreme price volatility 

or a transportation curtailment, TEC would use ULSD as the Facility’s fuel. TEC is not 

proposing to use ULSD as fuel in the Facility’s combustion turbines except during actual or 

effective curtailment events. The exception to this rule would be during commissioning and 

performance testing when TEC would employ ULSD in the Facility’s combustion turbines even 

if natural gas is available.”

DEQ also found the following document published by the US Energy Information Administration: 

 

1 DEQ subsequently learned that Northwest Natural Gas would not be the supplier to Troutdale Energy Center, but 

the information from Northwest Natural was still informative.
DEQ Response to Comments – Troutdale 

Energy Center

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March 5, 2014

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503-229-5534

An Analysis of Price Volatility in Natural Gas Markets, Energy Information Administration, Office of Oil 

and Gas, August 2007, available at: 

http://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2007/ngprivolatility/ngprivolatility.pdf .

This document provided a detailed technical analysis of natural gas price volatility and the factors that 

affect prices and volatility. 

The document includes the following statements:

“This article presents an analysis of price volatility in the spot natural gas market, with particular 

emphasis on the Henry Hub in Louisiana.” (page 1)

“Factors on the supply side that may affect prices, and hence volatility, include variation in 

natural gas storage, production, imports, or delivery constraints.” (page 2)

“Disruptions caused by severe weather, operating mishaps, or planned maintenance can also 

cause short-term tightness in natural gas supply.” (page 2)

“On the demand side, temperature changes tend to be one of the strongest short-term influences. 

During cold months, residential and commercial end users consume more natural gas for heating 

needs, which places upward pressure on prices. If unexpected or severe weather occurs, the effect 

on prices intensifies because supply is often unable to react quickly to the short-term demand 

response, especially if the natural gas transportation system is operating at full capacity. Under 

these conditions, prices must rise high enough to reduce the demand for natural gas.” (pages 2 

and 3, emphasis added)

“The highest volatility levels in any year tend to occur from October through February. December 

through February are generally the coldest months of the year, and demand for natural gas rises 

sharply during these months as heating needs dominate the market.” (page 6)

Based on the above, Troutdale Energy Center’s proposed use of ULSD in all turbines is consistent with

limiting the use of ULSD to only those times when the natural gas supply is “curtailed”, where DEQ now 

understands curtailment to mean curtailment initiated by a government entity, a gas supplier or gas 

transporter, as well as “effective curtailment” as indicated by extreme price volatility.

DEQ does not have expertise in the area of natural gas pricing and is unable to precisely define “extreme 

price volatility”. However, DEQ notes that extreme price volatility might reasonably be indicated by 
DEQ Response to Comments – Troutdale 

Energy Center

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503-229-5534

sharp upward “spikes” in natural gas spot prices. Alternatively, actual information from gas suppliers or 

transporters might be available and could be used to show gas deliverability problems.

Finally, the use of ULSD for maintenance and testing purposes needs to be specifically allowed.

DEQ has revised condition 30 in the final permit to state that the combustion turbines must burn only 

natural gas except as follows:

 All combustion turbines (EU1, EU2 and EU3) may burn ULSD fuel for the purpose of 

commissioning, equipment maintenance and testing, and emissions source testing. Such use must 

be held to the minimum amount required to accomplish the activity.

 All combustion turbines (EU1, EU2 and EU3) may burn ULSD fuel in the event of natural gas 

curtailment, not to exceed 720 hours per turbine per calendar year.

o For the purpose of this permit condition, curtailment means actual or effective 

deliverability events related to either natural gas commodity supply or transportation 

curtailment.

o Actual or effective deliverability events may be demonstrated by keeping records of 

announcements by gas suppliers, gas transporters, or government entities; or by keeping 

records demonstrating extreme price volatility in day to day spot prices for the gas 

pipeline that supplies the facility.

Monitoring condition 31 has also been revised to account for the changes to condition 30.

Comment:

II.B. DEQ should exercise its discretionary authority to implement BACT during periods of startup and 

shutdown for EU1/EU2/EU3.

Given the purpose of this plant as a wind-integration facility, DEQ and the permittee anticipate 1,000 

annual startup/shutdown cycles for the simple cycle units and approximately 200 annual startup/shutdown 

cycles for the combined cycle unit, totaling 321-330 hours per turbine per year. 

Given the substantial number of startup/shutdown cycles expected at this facility, NEDC requests that 

DEQ exercise its discretion in establishing a secondary BACT standard for periods of startup and 

shutdown. See, e.g., In re: Tallmadge Generating Station, PSD Appeal No. 02-12, (EAB, May 22, 2003) 

(discussing BACT applicability in startup/shutdown context). Such action would serve the public interest 

by protecting public health and the environment because a significant portion of this facility’s emissions 

will occur during startup/shutdown.
DEQ Response to Comments – Troutdale 

Energy Center

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March 5, 2014

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503-229-5534

Response:

DEQ does not agree with commenters.

The applicant submitted the following information in the permit application:

 the time periods required for startups and shutdowns, and

 estimates of the emissions that would occur during those time periods.

In essence, a startup will take a certain amount of time, and during that time there will be a certain amount 

of emissions. Alternatively, a startup will cause a certain amount of emissions, and those emissions will 

occur over a certain period of time. In other words, the amount of time required for a startup and the 

amount of emissions that occur during a startup are directly related to one another such that specifying the 

time also specifies the emissions and specifying the emissions also specifies the time. Therefore, with 

regard to startups and shutdowns, a time limit or an emissions limit are equivalent and either serves to 

limit the other. DEQ therefore concludes that the time limits alone are sufficient and sees no need to 

change the BACT determination for startups and shutdowns.

Comment:

II.C. This permit’s GHG BACT determination differs significantly from determinations made by DEQ’s 

peer agencies in other jurisdictions for the same equipment employed at this plant.

NEDC is concerned that DEQ accepted the permittee’s GHG BACT analysis and rationale underlying this 

analysis, even though other facilities employing the same equipment for the same purpose are currently

permitted to emit significantly less GHG than has been proposed here. The permittee set forth two 

rationales for a 1000 lb CO2e/MWh limit for EU1 and 1707 lb CO2e/MWh limit for EU2/EU3. First, it 

explained that TEC’s wind-integration function necessitates a higher limit because the facility necessarily 

burns more fuel while ramping up electric production. Second, it explained that the permit incorporates 

ULSD, a higher-emitting fuel. TEC Permit Review Report, at 19. Each of these reasons is flawed, leading

to a BACT analysis that is legally deficient and insufficiently protective of global climate.

First, only the simple cycle turbines are intended to rapidly ramp production up and down. EU1, the 

combined cycle unit, is not nearly as well suited for this task and is intended to provide baseload or midpeaking power as opposed to rapid wind-integration capability. This is further evidenced by the permitted 

number of startup/shutdown cycles for EU1. As such, the permittee’s first rationale simply does not apply 

to EU1—it only applies to EU2/EU3. NEDC requests that DEQ reconsider the GHG BACT 

determination for EU1 in light of that emission unit’s express function and purpose. Upon this review, 

DEQ should consider other recently permitted combined cycle turbines that have adhered to GHG limits 
DEQ Response to Comments – Troutdale 

Energy Center

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Permit writer: George Davis

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503-229-5534

substantially lower than 1000 lb CO2e/MWh. See, e.g., FPL Port Everglades Combined Cycle BACT 

Determination, at 13 (832 lb CO2e/MWh for natural gas; 1,176 lb CO2e/MWh for ULSD), available at

http://www.epa.gov/region4/air/permits/ghgpermits/porteverglades/PortEverglades_PD.pdf.

Second, the permit’s GHG BACT analysis is flawed because it combines emissions for two very different 

fuels under one standard. Most of this ACDP’s emission-limiting permit conditions explicitly establish 

different limits for natural gas and ULSD combustion. Without any reason given, however, the permit 

treats GHGs differently by combining the GHG emission limit for both fuels under one standard. This 

approach yields an improper BACT determination because it allows TEC to benefit from a more relaxed 

GHG emission limit resulting from incorporation of ULSD into the emission rate, even if it only ever 

burns natural gas. Moreover, EPA has determined in its own permitting decisions that combining ULSD 

and natural gas into one BACT emission limit is not appropriate. Id.

Therefore, NEDC suggests that DEQ cure this legal deficiency in the permit by treating GHGs the same 

way as it treated most every other pollutant in this permit—by establishing separate standards for natural 

gas combustion and ULSD combustion. Doing so will require TEC to meet the limit actually applicable to 

the facility’s operating situation (i.e., when combusting natural gas or ULSD). Moreover, it will establish 

a useful BACT standard that can be relied upon by other, similar facilities. For example, the PerennialWindChaser plant, which recently submitted a PSD permit application to DEQ, has indicated its GHG 

BACT analysis is based on the determination for this permit.

Most importantly, at least one recently-permitted facility uses the exact same simple cycle turbines for the 

exact same purpose as TEC, and yet that facility received a substantially lower GHG BACT 

determination. That facility, the Pio Pico Energy Center, permitted by EPA, incorporated several GE 

LMS100 simple cycle turbines in order to integrate wind and solar energy into the grid. The turbines were 

permitted 500 startup/shutdown cycles per year. EPA determined GHG BACT for that facility was 

1,328lb/MWh, approximately 23% less than proposed for TEC. See PSD Permit for Pio Pico Energy 

Center, available at http://www.regulations.gov/#!documentDetail;D=EPA-R09-OAR-2011-0978-0014; 

see also BACT Determination for Puget Sound Energy Fredonia Station, at 5-31, available at 

http://www.ecy.wa.gov/programs/air/psd/PSD_PDFS/PSE-Fredonia_Rev2_111031.pdf (LMS100 GHG 

BACT of 1,138 lb CO2e/MWh, but no indication of using this facility for windpower integration).

Based on the above, NEDC requests that DEQ fully reconsider its GHG BACT determination for both the 

combined cycle and simple cycle units at TEC. This analysis should provide separate standards for natural 

gas and ULSD. For natural gas specifically, a determination for EU1 should, at minimum, be below 850 

lb CO2e/MWh based on review of other existing permits. For EU2/EU3, 1,328 lb CO2e/MWh appears 
DEQ Response to Comments – Troutdale 

Energy Center

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503-229-5534

feasible and appropriate based upon the Pio Pico Energy Center permitting decision, and DEQ should 

consider adopting this standard as BACT for these emission units.

Response:

DEQ has reconsidered the GHG BACT analysis as requested by the commenters. DEQ reviewed the PSD 

permits referred to by commenters, and requested additional information from the applicant about 

proposed turbine operating scenarios and turbine performance and emissions under a number of operating 

loads.

Regarding turbine operating scenarios, the applicant provided the following:

“The combined-cycle power plant is intended to provide base load power. However, as with 

most generation units in the Pacific Northwest, due to the variability of renewable and hydrogeneration output, the combined-cycle power plant at the Troutdale Energy Center could also be 

load following. The combined-cycle plant is therefore not comparable to base load resources in 

other parts of the country where intermittent renewable energy resources do not represent a 

significant portion of the region’s capacity and energy. The combined-cycle plant will follow net 

load after hydropower and wind generation which are typically the first call resources. The 

combined-cycle power plant is not designed to provide power for short term, sudden demand 

surges. That sort of peak duty cycle would normally be met through simple-cycle combustion 

turbines. However, the combined-cycle plant is expected to operate as low as 50 percent load 

(burning natural gas) so as to be able to ramp up more efficiently and fill base load needs as wind 

and hydro resources diminish. This flexibility reduces the need to operate less efficient resources 

and makes the combined-cycle unit an optimal reserve generation resource for balancing 

unscheduled variations in output from variable output generation resources like wind turbines.”

2

“The simple-cycle power plant is intended to provide peaking capacity and its output can be 

changed almost instantaneously to facilitate the integration of variable output generation 

resources like wind and solar generation. This is in contrast to the typical simple-cycle generation 

unit that is operated as a load following and cycling resource. The significant supplies of wind 

generation in the Northwest (particularly along the Columbia River Gorge) exhibit rapid and 

concentrated fluctuations in output and, when combined with forecast errors, create significant 

energy imbalances in real time that have been well documented by large Northwest transmission 

system operators (e.g. BPA, PacifiCorp, PGE).”

3

 

2 Letter to George Davis, Oregon DEQ, from Troutdale Energy Center, December 9, 2013, page 3

3 Letter to George Davis, Oregon DEQ, from Troutdale Energy Center, December 9, 2013, page 4
DEQ Response to Comments – Troutdale 

Energy Center

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Permit writer: George Davis

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503-229-5534

DEQ concludes that all turbines at the proposed facility are intended to operate at variable loads and to 

rapidly ramp up power production. Regarding turbine performance and GHG emissions, the applicant 

provided information in two tables4. The relevant information from the tables is shown below:

Low Load Operating and Performance Scenarios:

Table 1

Simple Cycle Combustion Turbine 

Proposed BACT: Annual Average 1,707 CO2 lb/MWh 

Fuel Type NG NG NG NG ULSD ULSD ULSD NG ULSD

Load Level (%) 100 75 50 25 100 75 50 SUSD SUSD

Gross Plant Output (kW/hr, with 10% 

degradation factor) 95,663 71,545 47,467 23,341 91,574 68,675 45,791

Fuel Flow (MMBtu/hr, HHV)1 929.5 736.4 555.2 356.6 893.6 716.4 541

CO2 Emissions (lb/MWh equivalent 

gross w/10% degradation) *

1,136 1,203 1,367 1,786 1,591 1,701 1,927

CO2 (tons/hr) 54 43 32 21 73 58 44 30 40

Hours / Yr ** 0 438 1,840 4,713 0 0 1,440 203 127

CO2 (tons) 0 18,854 59,702 98,239 0 0 63,530 6,097 5,081

Output (MWh equivalent, gross) 0 31,337 87,319 110,001 0 0 65,946 0 0

Notes: * GHG Emission Factors provided by 40 CFR Part 98, Table C-1

** Estimated based on a potential operating scenario

Table 2

Combined Cycle Combustion Turbine 

Proposed BACT: Annual Average 1,002 CO2 lb/MWh

HRSG Firing1 Unfired Fired Unfired Unfired Unfired Unfired

Fuel Type1 NG NG NG NG ULSD ULSD NG ULSD

Load Level (%) 100 100 75 50 100 60 SUSD SUSD

Gross Plant Output (kW/hr, with 10% 

degradation factor) 359,622 411,660 278,514 210,618 285,777 185,508

Fuel Flow (MMBtu/hr, HHV) 2,595 3,092 2,106 1,662 2,298 1,599

CO2 Emissions (lb/MWh equivalent 

gross w/10% degradation) *

844 878 884 923 1,311 1,406

CO2 (tons/hr) 152 181 123 97 187 130 97 130

 

4 Tables were originally provided in the letter referenced in footnotes 1 and 3, but contained errors. Corrected tables 

were provided by email on December 20, 2013.
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

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Permit writer: George Davis

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503-229-5534

Hours / Yr ** 613 613 613 5,158 0 1,440 277 45

CO2 (tons) 93,027 110,827 75,485 501,178 0 187,760 26,851 5,853

Output (MWh equivalent, gross) 220,520 252,430 170,785 1,086,455 0 267,158 0 0

Notes: * GHG Emission Factors provided by 40 CFR Part 98, Table C-1

** Estimated based on a potential operating scenario

The Proposed BACT: Annual Average values in the first row of each table are the total annual CO2

emissions divided by the total annual electrical power output for the scenarios in the tables, calculated as 

follows:

[sum of all values in the row labeled CO2(tons)] x 2000 lb/ton

[sum of all values in the row labeled Output (MWh equivalent, gross)]

Parts of the tables are copied below, and DEQ has added lines showing the Percent increase in CO2 

emissions in lb/MWh over full load. For both types of turbine, examination of the tables shows that the 

emission rate in lb/MWh becomes higher at low load. The calculated Percent increase in CO2 emissions 

in lb/MWh over full load also illustrates this increase.

Simple Cycle Combustion 

Turbine

Fuel Type NG NG NG NG ULSD ULSD ULSD

Load Level (%) 100 75 50 25 100 75 50

CO2 Emissions (lb/MWh 

equivalent gross w/10% 

degradation)21,136 1,203 1,367 1,786 1,591 1,701 1,927

Percent increase in CO2 

emissions in lb/MWh over 

full load -- 6% 20% 57% -- 7% 21%

Combined Cycle Combustion 

Turbine 

HRSG Firing1 Unfired Fired Unfired Unfired Unfired Unfired

Fuel Type1 NG NG NG NG ULSD ULSD NG

Load Level (%) 100 100 75 50 100 60 SUSD

CO2 Emissions (lb/MWh 

equivalent gross w/10% 

degradation)2844 878 884 923 1,311 1,406

Percent increase in CO2 

emissions in lb/MWh over 

full load -- -- 5% 9% -- 7%
DEQ Response to Comments – Troutdale 

Energy Center

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Tables 1 and 2 (on page 23) also show GHG emissions in tons per hour for each scenario. DEQ notes that

pollutant emission rates are typically at a maximum when equipment is operated at its maximum rate, and 

indeed the tables indicate that GHG emission in tons per hour are at their maximum at full load and are 

lower at low loads. However, and perhaps counter-intuitively, GHG emissions in pounds per megawatthour are at their minimum at full load and are higher at low loads. DEQ understands that all combustion 

turbines exhibit the same basic performance characteristics; that is, they operate at maximum efficiency at 

full load and at lower efficiency at lower loads. Lower efficiency at lower loads means using more fuel 

per MWh generated. Since GHG emissions are directly related to the amount of fuel used, using more 

fuel per MWh at lower loads also means emitting more GHGs per MWh.

DEQ recognizes that operating combustion turbines at low load, where they are less efficient, seems to 

contradict the idea that BACT for combustion-derived GHGs is generally considered to be the use of 

equipment that exhibits the highest energy efficiency.GHG BACT for this type of facility must be 

considered within the context of electrical power generation overall, particularly wind energy. 

Availability and reliability of wind may vary unexpectedly resulting in variable output from wind 

generation resources. One of the stated purposes of the Troutdale Energy Center is to integrate with wind 

power, which means this facility is intended to provide rapidly available energy to “fill in” when wind 

power declines. This results in the need to operate this facility at varying loads, a mode of operation that 

is inherently less efficient than operating continuously at full load. This is an unavoidable consequence 

that will often result in a higher GHG emission rate, on a lb/MWh basis, when the facility is operating.

The fact that wind power is available at times means that, generally, less fuel overall must be burned to 

generate electricity. So, while an individual generating facility may have to operate in a less efficient 

manner, the electrical generating system as a whole is able to be more energy efficient, thus broadly 

achieving the energy efficiency goal of GHG BACT. Finally, DEQ notes that while low-load operation is 

less efficient, the actual GHG emission rate on a ton per hour basis is lower when operating at low load.

DEQ reviewed the GHG BACT limits for the facilities identified by the commenters, Port Everglades 

Energy Center5, Pio Pico Energy Center6and Puget Sound Energy Fredonia Generating Station 

Expansion Project7. The GHG BACT limits for these facilities are show below, along with the full load 

GHG emission rates for the turbines at the proposed Troutdale Energy Center (TEC):

 

5 Referenced on page 17 of this document

6 Referenced on page 18 of this document

7 Referenced on page 18 of this document
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

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503-229-5534

Facility Turbine 

generator 

type

GHG BACT 

limit

lb/MWh

TEC turbine emission rate at 

full load with 10% 

degradation factor

lb/MWh

Port Everglades Energy Center

Project consists of three 250 MW 

combustion turbine generators plus one 

500 MW steam turbine generator

without duct burners

Combined 

cycle

832 lb/MWh 

(natural gas)

1,176 lb/MWh 

(ULSD)

844 lb/MWh (natural gas)

without duct firing

878 lb/MWh (natural gas)

with duct firing

1,591 lb/MWh (ULSD)

Pio Pico Energy Center

Project consists of GE LMS100 natural 

gas-fired combustion turbine generators

Simple 

cycle

1,328 lb/MWh

(natural gas)

1,136 lb/MWh (natural gas)

Fredonia Generating Station Expansion 

Project

Project has several combustion turbine 

options, including 

two GE LMS100 turbines

Simple 

cycle

1,138 lb/MWh

(natural gas)

1,136 lb/MWh (natural gas)

DEQ notes that the GHG emission rates for the turbines at the proposed Troutdale Energy Center at full 

load when firing natural gas are generally comparable to the BACT limits shown above. DEQ further 

notes that the documents referenced by the commenters did not discuss GHG emission rates in lb/MWh at 

low load, nor did DEQ find any other documents related to these facilities that discussed GHG emission 

rates in lb/MWh at low load. It appears to DEQ that the BACT limits were set at the full load emission 

rates, and that the BACT limits above would limit the operation of these facilities to full or close to full 

load at all times. As discussed above, consideration of emission rates at low load is appropriate in the 

BACT determination for the TEC facility given its relation to wind power.

A BACT determination cannot be used to redefine a facility. The stated purpose of the proposed 

Troutdale Energy Center is to provide base load, load following and peaking power, and this requires the 

facility to operate all combustion turbines at low loads much of the time. DEQ believes that setting GHG 

BACT limits at levels that can only be achieved at or near full load would require the applicant to operate 

only at or near full load at all times. This would prevent the facility from operating in the intended manner 

and would constitute redefining the facility to a base-load only generating plant. Therefore DEQ cannot 

set GHG BACT limits at or near levels that can only be achieved at full load.
DEQ Response to Comments – Troutdale 

Energy Center

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March 5, 2014

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Permit writer: George Davis

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The applicant has presented potential operating scenarios in Tables 1 and 2 (on page 23) which might 

reasonably occur in practice and which DEQ believes represent reasonable worst-case scenarios. The 

GHG BACT limits proposed in the draft permit are based on these scenarios and properly take into 

account the higher GHG emission rates (on a lb/MWh basis) at lower loads.

In consideration of all of the above, DEQ does not agree with commenters and finds that the GHG BACT 

limits proposed for Troutdale Energy Center’s combustion turbines are reasonable and correct for the way

this particular facility is intended to operate.

With respect to the comment that DEQ should establish separate GHG BACT limits for natural gas and 

ULSD operation, DEQ notes that the proposed GHG BACT limits differ significantly from other

proposed BACT limits in the draft permit in that the GHG BACT limits are long-term limits (annual 

average) as opposed to short-term limits (averaged over hours). DEQ also notes that the proposed GHG 

BACT limits are based on a reasonable annual operating scenario that accounts for all potential modes of 

operation. If separate GHG limits were established for natural gas and ULSD, they would be established 

in much the same way, based on potential operating scenarios that are reasonably possible and reflect the 

stated purpose of the facility. Recalculating limits in this manner will not serve to further limit GHG 

emissions from this facility. DEQ therefore does not agree with commenters that there is a legal 

requirement to establish separate GHG BACT limits in terms of lb/MWh for natural gas and ULSD.

Comment:

III.DEQ may wish to update permit conditions 47 and 49 to account for recently proposed GHG NSPS 

covering new stationary combustion turbines.

Permit conditions 47 and 49, together, anticipate promulgation of a GHG NSPS covering EU1, the 

combined cycle unit, as an “affected source” and anticipate that EPA will codify this rule in 40 CFR 60, 

subpart TTTT. EPA’s recently proposed GHG NSPS, however, suggests that it may be prudent for DEQ 

to make several changes to these permit conditions.

First, EPA has indicated it may codify this rule under either subpart TTTT or subpart KKKK. See 

Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility 

Generating Units, EPA-HQ-OAR-2013-0495; FRL-9839-4, at 37, available at

http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposal.pdf. Conditions 47 and 

49 do not reflect this possibility.

Second, EPA’s proposed rule has the potential to also cover EU2/EU3 as affected sources if those 

emission units sell more than one-third of their potential output capacity to the grid on a three year rolling 
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

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Permit writer: George Davis

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basis. Id. at 81-87. NEDC recognizes that this scenario is unlikely because these units are not intended to 

provide baseload power. Nonetheless, the wind-shaping purpose of these emission units and the lack of 

data as to hours of operation or total sales for these emission units in the review report has led the 

commenters to bring this issue to DEQ’s attention. If the permittee intends to sell more than one-third of 

EU2/EU3’s potential output, the units will be unable to meet EPA’s proposed NSPS of 1,100 lb 

CO2e/MWh based on the BACT determination for those units.

Response:

Conditions 47 and 49 are monitoring requirements for CO2 and ammonia, respectively, and do not refer to 

the requirements of Subpart TTTT. DEQ believes commenters are referring to condition 44 of the draft 

permit, which requires the permittee to comply with 40 CFR Part 60 Subpart TTTT. DEQ agrees with 

commenters and has revised this condition to read as follows:

“Upon the dates specified in 40 CFR Part 60 Subpart KKKK or TTTT, whichever applies, the permittee 

must comply with the relevant Subpart KKKK or TTTT CO2 standards as applicable to EU1, EU2 and 

EU3, including all applicable performance testing, recordkeeping and reporting requirements.”

DEQ appreciates commenters bringing the potential compliance issue to DEQ’s attention. DEQ will 

review compliance with Subpart KKKK or TTTT, whichever is applicable, after it is promulgated. DEQ 

also expects to expand condition 44 in a future permit action to add the necessary details from the final 

version of whichever rule EPA revises.

Comment:

IV. Conditions 50 and 51 will not provide DEQ adequate notice if this facility is in noncompliance with 

emission limits established in this permit.

This ACDP establishes emission limits and PSELs for PM and VOCs. Condition 50 provides that TEC 

must undertake a source test every 5 years for VOCs. Condition 51 provides that TEC must undertake a 

source test for PM every 10 years when combusting natural gas, and never, except immediately following 

construction, when combusting ULSD.

This pre-construction permit, as written, is intended to eventually be turned into a Title V operating 

permit. 42 USC § 7661(c) provides that a Title V operating permit must contain “conditions as are 

necessary to assure compliance with applicable requirements” of the Clean Air Act. The 2010 Stationary 

Source Compliance Monitoring Strategy, EPA’s definitive guidance on stationary source monitoring 

developed in conjunction with the National Association of Clean Air Agencies, states that a full 

compliance evaluation “should be conducted, at a minimum, once every two Federal fiscal years at all 
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Title V major sources.” Compliance Strategy, at 9, available at 

http://www.epa.gov/compliance/resources/policies/monitoring/caa/cmspolicy.pdf . Per that guidance, a 

full compliance evaluation incudes source testing for all regulated pollutants at a facility.

Conditions 50 and 51 do not comply with 42 USC § 7661(c) because source tests that are spaced five or 

ten years apart (or in the case of PM from ULSD combustion, are simply never conducted after 

construction) cannot possibly provide DEQ with sufficient information to “assure compliance” with PM 

and VOC limits established by DEQ. Nor do conditions 50 and 51 comport with the spirit or meaning of 

the Monitoring Strategy because source testing at 5-10 year intervals is substantially longer than the two 

years recommended in the guidance. In other words, a source test conducted five or ten years earlier will 

not be a reasonable proxy for current emissions. Therefore, NEDC requests that DEQ change permit 

conditions 50 and 51 to require source testing when burning natural gas and ULSD every 14 months for 

VOC and PM. This should not be a significant hardship for the permittee, as it is already required to 

undertake source testing on this 14-month schedule for NOx and CO. See TEC Permit, Condition 48. 

Most importantly, though, a 14-month schedule should provide DEQ with sufficient information to

provide it with reasonable assurance that TEC is in compliance with its VOC and PM limits.

Response:

Commenters cite EPA’s 2010 Stationary Source Compliance Monitoring Strategy, and state “Per that 

guidance, a full compliance evaluation incudes source testing for all regulated pollutants at a facility.”8

DEQ disagrees with this statement and point out that the 2010 Stationary Source Compliance Monitoring 

Strategy states, on page 5, that a Full Compliance Evaluation includes “A stack test where there is no 

other means for determining compliance with the emission limits. In determining whether a stack test 

is necessary, States/locals should consider factors such as: size of emission unit; time elapsed since 

last stack test; results of that test and margin of compliance; condition of control equipment; and 

availability and results of associated monitoring data.” DEQ will be inspecting the facility consistent 

with DEQ’s Compliance Monitoring Strategy. DEQ also considered the factors discussed below in 

determining the frequency for certain stack tests.

Both VOC and CO are byproducts of incomplete combustion, and emissions of both would be controlled, 

to some extent, by the oxidation catalyst emission control system that is required for all three turbines. 

DEQ regards CO as a reasonable surrogate for VOC9and compliance with the CO limit reasonably 

 

8

See page 24.

9 EPA has used CO as a surrogate for organic HAP. See, for example, the preamble to the National Emission 

Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and 
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implies compliance with the VOC limits. DEQ therefore does not agree that VOC testing every 14 

months is necessary.

However, upon reconsideration of the proposed testing schedule, DEQ has revised condition 50 to require 

additional testing while using ULSD as follows:

Following the initial test, subsequent tests while burning ULSD must be performed as follows:

1. not more than 60 months after the first test; and

2. thereafter, not more than 10 years after the most recent test.

The requirements for testing while using natural gas were not changed.

Permit condition 51 requires emissions testing of the turbine exhausts for PM. Combustion of natural gas 

produces very little PM and the amount of PM produced is not likely to change over time. Therefore DEQ 

does not believe that more frequent PM testing while using natural gas is needed.

Upon reconsideration of the proposed testing schedule, DEQ has revised condition 51 to require 

additional testing while using ULSD as follows:

Following the initial test, subsequent tests while burning ULSD must be performed as follows:

1. not more than 60 months after the first test; and

2. thereafter, not more than 10 years after the most recent test.

Comment:

V. The public interest, including the public’s interest in visibility in the Gorge, weighs heavily in favor of 

DEQ carefully considering and resolving the above-mentioned issues.

Previously mentioned issues in this permit, unless resolved, have the potential to undermine progress that 

has been made in addressing visibility in the Columbia River Gorge and Mt. Hood pursuant to the Oregon 

Regional Haze Plan. Although DEQ and Columbia River Gorge Commission have taken important steps 

to address visibility degradation in these areas, issues with this permit, unless corrected, would allow TEC 

to impact Class I Areas like Mount Hood, as well as National Scenic areas like the Columbia River 

Gorge, to a greater extent than necessary.

This is problematic in light of federal requirements that visibility should be improved to “natural

conditions” for Class 1 areas by 2064 and that reasonable further progress must be made toward this goal. 

 

Process Heaters at 7138 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013. As organic HAP are also 

VOC, DEQ believes CO is a reasonable surrogate for VOC.
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40 C.F.R. § 41.308(d)(1) (2013). Most importantly, though, this is problematic from the standpoint of the 

public’s overall enjoyment of Mount Hood and the Gorge.

This permit’s review report’s discussion of the Air Quality Related Values (AQRV) analysis recognizes 

that, in some cases, visibility and deposition impacts within the Gorge are greater than in Class I Area 

thresholds. TEC Permit Review Report, at 46-47. The review report deflects this by stating that the Gorge 

is not expected to reach ‘natural conditions’ and that these results should be considered concurrently with 

improvements in visibility from emissions reductions from the PGE-Boardman power plant in Oregon 

and the Centralia plant in Washington.

NEDC recognizes that the Gorge is not subject to the federal Regional Haze Program. However, in the 

Columbia River Gorge Air Study and Strategy of 2011, DEQ stated that “[t]he goal for visibility in the 

Gorge is continued improvement using the same approach used in the federal Regional Haze Program.” 

See Columbia River Gorge Air Study and Strategy of 2011, at 6, available at

http://www.deq.state.or.us/aq/gorgeair/docs/11aq035_gorgeAirStudy.pdf (emphasis added). DEQ can 

help ensure that this goal is best met and that the public interest is best served by curing the several issues 

with TEC’s permit, highlighted earlier in this comment. Thank you for your careful consideration of these 

comments.

Response:

Troutdale Energy Center submitted an analysis of the facility’s impacts on the Columbia River Gorge 

National Scenic Area (CRGNSA) which indicated certain impacts greater than what is allowed in Class I 

areas. The analysis was based on reasonable worst-case emissions scenarios. DEQ reviewed the analysis 

and after considering comments by federal agencies such as the U.S. Forest Service concluded the 

following:

“While not “zero”, the low and localized levels of TEC’s visibility and deposition impacts appear 

consistent with the dual goals of the Gorge Air Strategy of protecting and enhancing the scenic, natural, 

cultural and recreational resources as well as protecting and supporting the economy of the Columbia 

Gorge. We acknowledge that visibility improvement cannot be expected to reach ‘natural conditions’ as is 

the case for pristine Class I wilderness areas.”10

None of the emissions scenarios used in the analysis are affected by the commenters’ comments, and 

DEQ does not agree with commenters that “Previously mentioned issues in this permit, unless resolved, 

 

10 Review of the USFS technical analysis of TEC impacts on the Scenic Area, appendix to letter from Andrew 

Ginsburg, DEQ, to Ms. Lynn Burditt, U.S. Dept. of Agriculture-Forest Service, August 16, 2013
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have the potential to undermine progress that has been made in addressing visibility in the Columbia 

River Gorge and Mt. Hood pursuant to the Oregon Regional Haze Plan.”

Comments by Richard Till, Friends of the Columbia Gorge

Commenter:

Richard Till, Conservation Legal Advocate

Friends of the Columbia Gorge

rick@gorgefriends.org

Direct: 971-634-2032

General Office: 503-241-3762

Fax: (503) 241-3873

Comment:

Friends of the Columbia Gorge (“Friends”) has reviewed and would like to comment on the Department 

of Environmental Quality’s (“DEQs”) proposed air quality permit (“proposed permit”) for the Troutdale 

Energy Center (“TEC”) and supporting materials that were incorporated by reference. Friends is a nonprofit organization with approximately 5,000 members dedicated to protecting and enhancing the 

resources of the Columbia River Gorge. Our membership includes hundreds of citizens who live, work, 

and recreate in the Columbia River Gorge National Scenic Area (CRGNSA or National Scenic Area). 

Friends is concerned about the potential impacts of the TEC facility on the scenic, natural, recreational, 

and cultural resources of the Columbia River Gorge. This concern is supported by comments that have 

been submitted to the Oregon Energy Facility Siting Council (EFSC) by the Forest Service, the Columbia 

River Gorge Commission, and the National Park Service.1 These agencies have concluded that the facility 

would likely cause significant adverse impacts to the National Scenic Area and other significant 

resources, such as the Lewis and Clark National Historic Trail. While DEQ’s Clean Air Act regulations 

do not directly address these concerns, DEQ’s draft permit incorporates voluntary analysis that does 

address these impacts. DEQ should revise these supporting materials to be consistent with the conclusions 

reached by other expert agencies. 

The impacts from the TEC facility implicate several regulatory programs that overlap with DEQ’s federal 

Clean Air Act air quality regulations.2 These comments will address issues related to DEQ’s air quality 

permitting, the Columbia River Gorge Air Quality Strategy that was approved by the Columbia River 

Gorge Commission, and Oregon’s Energy Facility Siting Council (EFSC) regulations that prevent 

significant adverse impacts from air pollution to the Columbia River Gorge National Scenic Area. 
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__________

1

Forest Service, Columbia River Gorge Commission, and National Park Service comments are attached 

for reference.

2

Friends also signed onto comments submitted by the Northwest Environmental Defense Center dated 

October 14, 2013. 
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The Forest Service performed independent modeling and analysis and concluded that the project would 

contribute to significant adverse impacts to visibility and increase nitrogen deposition in the National 

Scenic Area. The Forest Service concluded that it was likely that the operation of the TEC would conflict 

with EFSC regulations that protect the National Scenic Area and conflict with the Gorge Air Quality 

Strategy. The Gorge Commission submitted comments to EFSC that supported the conclusions reached 

by the Forest Service and recommended that EFSC address these issues. The National Park Service also 

submitted comments to EFSC recommending protection of resources that are important to the Lewis and 

Clark National Historic Trail. To the extent DEQ has authority to provide analysis of impacts relevant to 

EFSC’s permitting authority, DEQ should be supporting the conclusions reached by the Forest Service, 

the Gorge Commission, and the National Park Service. 

A. The Troutdale Energy Center must comply with both the DEQ Clean Air Act standards and EFSC’s 

siting standards. 

The TEC is subject to three overlapping regulatory programs that are overseen by different agencies. The 

DEQ’s air quality permit program implements the federal Clean Air Act and Oregon’s state 

implementation plan. DEQ’s regulations only require that DEQ “encourage” the applicant “to 

demonstrate that these same emission increases or decreases will not cause or contribute to significant 

impairment of visibility on the Columbia River Gorge National Scenic Area (if it is affected by the 

source).”3 Modeling for impacts to the National Scenic Area is voluntary, not mandatory.4 DEQ’s draft 

permit only addresses mandatory elements of Clean Air Act permitting requirements. However, voluntary 

analysis that was included by reference does address impacts to the National Scenic Area. 

Independent of the Clean Air Act requirements, EFSC’s regulations require that EFSC make findings that 

the TEC not cause significant adverse impacts to the National Scenic Area, including impacts from air 

pollution.5 EFSC’s rules explicitly require EFSC consider impacts to visibility beyond the impact 

regulated by DEQ for protection of Class I airsheds. EFSC regulations also require that EFSC protect 

important recreation resources and scenic and aesthetic resources.6 EFSC’s scenic and aesthetic resource 

protection guidelines specifically require protection of resources identified in management plans, such as 

the Scenic Area Management Plan. If EFSC finds that operation of a facility would cause significant 

adverse impacts to the National Scenic Area, then it must review whether the public benefits of the 

facility of the facility outweigh the significant impacts. 
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__________

3 OAR 340-225-0070(3)(a). 

4 DEQ Memorandum at 44 (“These voluntary analyses are considered to be made for informational 

purposes.”) 

5 OAR 345-022-0040; OAR 345-021-0010(L)(C). 

6 OAR 345-022-0100; OAR 345-022-0080.
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Finally, the Columbia River Gorge Commission recently approved a Gorge Air Quality Strategy for the 

NSA. The Gorge Air Quality Strategy was required by the NSA Management Plan, which implements the 

Columbia River Gorge National Scenic Area Act. The Gorge Commission defended the Air Quality 

Strategy in the Oregon Court Appeals, which affirmed the Gorge Commission’s determination that the 

goal of “continued improvement” was consistent with the requirements of the National Scenic Area Act.7

The Gorge Commission submitted comments to EFSC recommending that EFSC’s proposed order 

address how the facility would address the goal of “continued improvement.”8 This mandate gains 

regulatory authority through EFSC’s independent requirement to protect the Scenic Area and scenic 

resources identified in the Management Plan, which incorporates the Gorge Air Quality Strategy. 

The DEQ’s draft permit and related materials include findings and analysis regarding the Clean Air Act 

permitting requirements, but also includes analysis and conclusions related to the Gorge Air Quality 

Strategy and findings that may be relevant to EFSC’s permitting standards. Friends encourages DEQ to 

revise its permitting materials to clarify its findings related to consistency with the Gorge Air Quality 

Strategy. Friends also encourages DEQ to revise its permitting materials to clarify that the Forest Service, 

as the Federal Land Manager, and the Gorge Commission, are the agencies with the relevant expertise for 

identifying thresholds for significant adverse impacts under EFSC’s regulations. 

1. DEQ’s supporting materials should be revised to clarify EFSC’s permitting authority related to impacts

to protected areas. 

__________
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7 Friends of the Columbia Gorge v. Columbia River Gorge Comm’n, 257 Or App 197, 202 (2013). 

8 The Columbia River Gorge Commission is given deference to its interpretations of the National 

Scenic Area Act and the Management Plan, which are federal laws. Friends of the Columbia Gorge 

v. Columbia River Gorge Comm’n, 171 P.3d 942, 953 (Or.App. 2007). The DEQ and EFSC, are 

“directed and provided authority to carry out their respective functions and responsibilities in 

accordance with the [Columbia River Gorge] compact executed under ORS 196.150 to 196.165 and 

the Columbia River Gorge National Scenic Area Act.” ORS 196.155. DEQ and EFSC are both 

responsible for ensuring that projects under their jurisdiction comply with any applicable standards 

from National Scenic Area Act and the Management Plan. 
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DEQ’s regulations only require that DEQ encourage the applicant to prepare modeling of impacts to the 

National Scenic Area. Accordingly, the applicant volunteered to prepare modeling of impacts to the 

National Scenic Area. DEQ’s proposed permit does not appear to include any conditions that directly 

address potential impacts to the National Scenic Area. The permitting materials do include a Draft Air 

Contaminant Discharge Permit Review Report for the Troutdale Energy Center, LLC.

9 This “Review 

Report” describes the air quality analysis that was prepared by the applicant and a voluntary air quality 

impacts assessment for the National Scenic Area.10 The Review Report states that the applicant’s analysis 

was reviewed and approved in a DEQ memorandum and incorporates that memorandum as an 

attachment.11 The DEQ staff memorandum contains the DEQ’s review of the applicant’s National Scenic 

Area analysis as well as a response to the Forest Service’s comments on that analysis. 12 The staff 

memorandum addresses the Forest Service’s comments regarding the Gorge Air Quality Strategy, but 

is silent on the Forest Service’s comments regarding the TEC’s likely inconsistency with the EFSC’s 

siting guidelines. 

Because the Forest Service is the Federal Land Manager responsible for the affected landscape, DEQ 

should be supporting the Forest Service’s conclusions regarding the likely impacts of the TEC 

facility. Instead, the staff memorandum disagrees with the Forest Service’s analysis and conclusions 

regarding consistency with the Gorge Air Quality Strategy. The staff memorandum states that the 

applicant’s methodologies were “reasonable” based on an excerpt of the Air Quality Strategy that 

states: “There is no scientific justification for selecting one air quality threshold over another as ‘the 

correct’ goal for the Gorge.”13 This excerpt from the Gorge Air Strategy that is taken out of context. 

The next paragraph of the Gorge Air Quality Strategy explains that “[t]he air agencies do not have 

the available funding or staff resources to establish a more prescriptive goal for the Gorge.”14 The

issues identified in the Air Quality Strategy were related to agency capacity for establishing a 

prescriptive goal for the entire Gorge, not the most appropriate methodology for assessing impacts 

from a specific project. 
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_________

9 Review Report/Permit No.: 26-0235-ST-01; Application Number: 027060. 

10 Id. at 23, ¶ 43. 

11 Id. at 23, ¶ 44. 

12 DEQ Memorandum; Date: 2 August 2013; To: George Davis, From: Svetlana Lazarev, Through: Phil Allen 

Subject: Troutdale Energy Center. 

13 DEQ Staff Memo at 46 (quoting Gorge Air Strategy at 6). 

14 Gorge Air Strategy at 7. 
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In the instant case, the Forest Service had the capacity to perform the analysis for the TEC project, 

performed that analysis, and concluded that the project would cause significant adverse impacts. The 

lack of capacity to prepare a Gorge-wide prescription is not a valid basis for dismissing the Forest 

Service’s conclusions for this particular proposal. 

In addition, the Forest Service’s analysis considered the air quality impacts to a small but significant 

portion of the National Scenic Area. The Forest Service expressed concern about impacts from 

nitrogen deposition exceeding thresholds for harm at the Sandy River Delta, which was designated a 

Special Management Area because of its important natural and recreational resources. The Forest 

Service’s more detailed focus and conclusions should not be disregarded because the air quality 

agencies did not have capacity to set Gorge-wide performance criteria. DEQ should revise it staff 

memorandum to acknowledge the validity of the Forest Service’s conclusions. 

The DEQ memorandum acknowledged that, even using the applicant’s modeling thresholds, the TEC 

facility would still exceed those thresholds. The staff memorandum states that “[t]he results . . . show 

visibility and deposition impacts that, in some cases, are greater than the . . . thresholds.”15 Thus, the 

staff memorandum appears to acknowledge that the impacts would exceed a threshold for significant 

impacts. Rather than accept that conclusion, the memorandum immediately dismisses the issue

because Gorge air quality is unlikely to achieve natural conditions that are the goal for Class I 

airsheds.16 The DEQ should revise its analysis to acknowledge that the applicant’s methodology is a 

valid basis for finding significant adverse impacts to portions of the National Scenic Area. While the 

Gorge may not reach “natural conditions,” exceeding thresholds “in some cases” would still 

constitute an adverse impact to protected resources.

2. The DEQ should revise its conclusions regarding consistency with the Gorge Air Quality strategy. 

To the extent DEQ has regulatory obligations under the Gorge Air Quality Strategy, the staff 

memorandum warrants revisions. The Gorge Air Quality Strategy states that “[t]he goal for visibility in 

the Gorge is continued improvement.”17 The Strategy also explains that the Gorge is unlikely to reach 

natural conditions that are the goal for Class I airsheds, but that air quality in the Gorge “can be expected 

to mirror the visibility improvement” that is required to occur in nearby Class I airsheds.18 The staff 

memorandum disagrees with the Forest Service’s conclusion that operation of the TEC facility would be 

inconsistent with the Gorge Air Quality Strategy. 

The DEQ staff memo argues that the TEC project would be consistent with the strategy because of the 

reduction of emissions from two coal-fired power plants.19 The reduction in emissions from the two coal-
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fired plants is completely unrelated to the TEC project and irrelevant to whether the TEC project will 

support or impair the goal of continued improvement in the Gorge. 

__________

15 DEQ Memo at 46 (emphasis added). 

16 Id.

17 Gorge Air Quality Strategy at 6. 

18 Id. 

19 DEQ Memo at 47. 
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The improvement to coal-powered plants is also irrelevant to whether the TEC facility would “mirror” 

improvements to Class I airsheds. In reality, the TEC facility is proposed in a uniquely unsuitable location 

for advancing the goals of the Gorge Air Quality Strategy. The TEC facility is proposed adjacent to the 

western gateway to the National Scenic Area, which would likely cause a disproportionate impact to the 

National Scenic Area compared to the likely impacts to Class I airsheds. The Applicant’s modeling, 

which shows acceptable impacts to Class I airsheds but significant impacts in portions of the National 

Scenic Area. Due to the location, the TEC facility would not further the goal of mirroring air quality 

improvements. 

In addition, the goal of continued improvement necessarily implies ongoing improvements to air quality. 

While reductions in emissions from coal-fired plants were a major improvement to visibility in the Gorge, 

those one-time measures will not ensure that there is continued, i.e., on-going improvements to visibility 

in the Gorge. Since coal plant improvements have already occurred, the improvements do not satisfy the 

need for continued improvement beyond implementation of those measures. DEQ should view the 

upgrades to coal-fired power plants as establishing a new baseline from which to measure the next steps 

in continued improvement. The construction of the TEC would undermine continued improvement 

beyond that new baseline. 

Finally, the DEQ’s reasoning essentially argues that TEC project’s air quality impacts will be mitigated

by permitting conditions for the coal-fired power plants. DEQ cannot demonstrate that there will be 

continued improvement by relying on the same mitigation for every new energy facility. While other air 

quality improvement efforts will support continued improvement, a new facility at the mouth of the 

National Scenic Area would impair those efforts and conflict with the goal. 

The Forest Service has commented that the TEC project would conflict with the goal of continued 

improvement. Similarly, the Gorge Commission has recommended that EFSC address the Gorge

Air Quality Strategy through its permitting process. Since the Gorge Commission approved the goal and 

successfully defended that goal in court, DEQ should be acknowledging the agencies conclusions. At the 

very least, the Forest Service’s conclusions should be acknowledged as reasonable. In addition, the DEQ 

should acknowledge the Gorge Commission’s recommendation that EFSC address consistency with the 

Gorge Air Quality Strategy through its siting regulations. 

B. Conclusion 

The Forest Service’s comment to EFSC explained that “it seems probable there may be cases where DEQ 

issues an air quality permit to a proposed new power plant where EFSC may determine not to issue a Site 
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Certificate based upon air quality impacts, or vice-versa.” Given this direction, the DEQ should revise its 

staff memorandum to clarify DEQ’s relationship with EFSC’s permitting standards. The DEQ should 

revise its staff memorandum to acknowledge that the Forest Service’s conclusions are reasonable and 

deserving of deference as the Federal Land Manager and agency with responsibility for monitoring air 

quality throughout the Gorge. 

Notably, acknowledging EFSC’s permitting authority does not put EFSC in the position of mandating 

specific pollution control technology that is regulated by DEQ. Instead, this is where EFSC’s balancing 

authority kicks in. EFSC’s regulations require the agency to balance the public benefits of the project 

against any significant adverse impacts to protected areas. If the benefits do not outweigh the impacts, the 

project would be denied. Alternatively, the applicant could modify the project to reduce the impacts to 

ensure compliance with both EFSC standards and DEQ standards. In either case DEQ would retain 

authority to approve the specific pollution control measures employed at the facility. 

In sum, EFSC should revise the supporting materials that were incorporated by reference into the draft 

permit for the TEC facility. Given the complex permitting process and the recommendations of several 

expert agencies, DEQ needs to clarify its findings and conclusions.

Thank you for the opportunity to comment. 

(note: attachment to the Friends of the Columbia Gorge comments are not included here)

Response:

DEQ does not agree that it should revise its conclusions regarding consistency with the Gorge Air Quality 

strategy or that DEQ’s supporting materials should be revised to clarify EFSC’s permitting authority 

related to impacts to protected areas. EFSC’s permitting authority is already defined by rule and further 

clarification by DEQ is not necessary. DEQ’s performed its review of the analysis based on DEQ’s 

applicable rules and regulations. 

Thresholds for evaluating the significance of visibility and other air quality related values (AQRVs) in 

federal Class I areas, which are pristine wilderness areas and national parks, have been long established

by the Environmental Protection Agency and Federal Land Managers, and are used in the PSD program.

Following DEQ guidance, these Class I area thresholds have been used for many years as reference points 

for the Columbia River Gorge, and were considered in TEC’s analysis of impacts in the Gorge. After

review of this analysis, DEQ concluded that TEC’s modeling methods, results, and conclusions were

sound. Based on the data, DEQ concluded that the proposed facility would not cause or contribute to 

significant adverse air quality impacts in the Gorge, or undermine the Gorge air quality strategy, as 
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defined in the Columbia River Gorge National Scenic Area Act and the Columbia River Gorge Air 

Quality Strategy.

Regarding the Forest Service review of the TEC Prevention of Significant Deterioration (PSD) modeling, 

DEQ gives great weight to the expertise provided by the USFS in air quality analysis. However, in this 

case, the department respectfully disagrees with some of the conclusions based on significance thresholds 

offered by the Forest Service.

In its evaluation of TEC’s air quality impacts on the Gorge, the USFS relied heavily on the significant 

impact thresholds used for Class I areas. These areas have the most restrictive criteria for defining 

“significant air quality impact” under the PSD rules. The Columbia River Gorge National Scenic Area is 

not a Class I area, but a mixed use area with both scenic and urban characteristics. As noted above, DEQ 

considers the Class I area thresholds as reference points when evaluating air impacts in the Gorge, and 

they can also provide a useful guide when evaluating the effectiveness of Best Available Control 

Technology required by DEQ rules. There is however no basis for requiring the use of Class I thresholds 

as a “standard” that must be met in the Gorge. DEQ is also guided by the definition of “adversely affect” 

as used in the Gorge Scenic Area Act, which defines an adverse impact as a “reasonable likelihood of 

more than a moderate impact,” considering the intensity, magnitude, duration and likehood of the impact, 

as well as other factors. 

The TEC PSD analysis showed that the proposed facility would have a minor impact on air quality at the 

very western edge of the Gorge, during very limited hours, and only under intermittent “worse-case”

operating conditions. Based on both the original TEC analysis and the review and re-analysis by the 

USFS, DEQ concludes that the proposed facility would not significantly worsen air quality or degrade 

natural resources in the Gorge, and would not undermine the overall strategy for visibility improvement in 

the Gorge. 

DEQ recognizes the special nature of the Gorge scenic area, and also that the National Scenic Area Act 

reflects the dual nature of the Gorge Scenic Area by establishing protection goals for both valued 

resources and local rural/urban economies in the Gorge. The Columbia River Gorge Air Quality Strategy 

does not impose a ban on growth or the development of new industries in and around the Gorge. In the 

coming years, increases in emissions and air pollution will likely occur as a result of growth in 

population, motor vehicle use, economic development, and other local, regional, and international 

activities. However, those emission increases will be offset by emission reductions from a wide variety of 

sources through state and federal regulations, including those adopted under the regional haze program. 

These reductions include cleaner motor vehicle and truck standards, cleaner fuels, and adding pollution 

controls to older industrial facilities such as the Boardman and Centralia coal-fired power plants. As a 
DEQ Response to Comments – Troutdale 

Energy Center

File No. 26-0235

March 5, 2014

Page 45 of 45

Permit writer: George Davis

davis.george@deq.state.or.us

503-229-5534

result, Class I areas and the Columbia River Gorge NSA are expected to see a sustained, net improvement

in air quality. Similar to the regional haze program, the goal for visibility in the Gorge is continued 

improvement over time. That means tracking the net change in air quality over time (increases and 

decreases) and ensuring sustained improvement. DEQ will evaluate the progress of this strategy for both 

Class I areas and the Columbia Gorge under its 2014 and 2018 regional haze plan work. 

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doc name: 26-0235-RTC-03052014.docx, March 5, 2014