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### 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 findin gs included in the permit record.

ISSUED TO: INFORMATION RELIED UPON:

Troutdale Energy Center, LLC Application Number: 027060

11 Martine Avenue, 9 th 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

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TABLE OF CONTENTS

LIST OF ABBREVIATIONS THAT MAY BE USED IN THIS PERMIT

................................ ................................ .. 3

COND ITIONAL AUTHORIZATION TO CONSTRUCT

................................ ................................ ........................... 4

PERMITTED ACTIVITIES

................................ ................................ ................................ ................................ .......... 4

EMISSIONS UNIT (EU) AND POLLUTION CONTROL DEVICE (PCD) IDENTIFICATIO N

.............................. 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

REPORT ING REQUIREMENTS

................................ ................................ ................................ ............................... 42

STANDARD ACDP REQUIREMENTS AND General Conditions

................................ ................................ ........... 44Permit number: 26

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LIST OF ABBREVIATION S THAT MAY BE USED I N THIS PERMIT

ACDP Air Contaminant Dischar ge 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 m onoxide

CO 2 Carbon dioxide

CO 2 e C arbon dioxide equivalent

CPMS Con tinuous 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 ga s 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

- Fluoro

Carbons

ID Identification number or label I&M Inspection and maintenance

NA Not applicable

NO

x Nit rogen oxides

NSPS New Source Performance Standard

O 2 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

PM 10 Particulate matter less than 10

microns in size

PM 2.5 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

SO 2 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 ac cordance 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 duratio n 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

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CONDITIONAL AUTHORIZ ATION 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 permit tee 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 Ope rating 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 discont inued for a period of 18 months or more or if construction is not completed within 18 months of the scheduled time. DEQ may extend th e 18 month period as allowed by the rules

.

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

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EMISSIONS UNIT (EU) AND POLLUTION CONTROL DE VICE (PCD) IDENTIFIC ATION

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 co ntrol

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 f ire 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

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EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECO RDKEEPING REQUIREMENTS

The following tables an d 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/

Param eter 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 c ontrol 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 asphalt 1 , 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 p lant 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

so urces 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

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

limited to those actions identified in condition 7 ; or

8.b. C onduct 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), a nd/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 creat e 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. Mon itoring 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 co ndition, 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

represen tative 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 acc ordance with conditions 17

, 31

, 37 and 59

.

Part 68 Risk Management Plan

13. Applicable Requirement Should this stationary source become s ubject 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 Par t 68]Permit number: 26

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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% CO 2 17

, 18 NA

OAR 340

- 228

- 0210(1)(b) 16 PM (fuel burning equipment) 0.1 gr/dscf

@12% CO 2 17

, 18 NA

BACT

(OAR 340

- 224

- 0070) 19 All o wed 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 ppm dv (gas) & 5.5

ppm dv (ULSD)

EU2 & 3: 2.5

ppm dv (gas) & 3.8 ppm dv (ULSD) 40

, 42 48

BACT

(OAR 340

- 224

- 0070) 22 CO EU1: 3.3 ppm dv (gas) & 9.0

ppm dv (ULSD)

EU2 & 3: 6.0

ppm dv (gas & ULSD) 41 41

BACT

(OAR 340

- 224

- 0070) 23 VOC EU1: 2.0 ppm dv (gas) & 5.0

ppm dv (ULSD)

EU2 & 3: 3.5

ppm dv (gas) & 5.0 ppm dv (ULSD) NA 50Permit number: 26

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Applicable Requirement Condition

Number Pollutant/

Parameter Limit/Standard Monitoring

Condition Testing

Condition

BACT

(OAR 340

- 224

- 0070) 24 CO 2 EU1: 1000

lb/MWh

EU2 & 3: 1707

lb/MWh 47 NA

BACT

(OAR 340

- 224

- 0070) 26 H 2 SO 4 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 , EU 1 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 cale ndar 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 ppm dv 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 SO 2 20 grains per

100 s tandard

cubic feet 37

, 46 NA

40 CFR Part 60, Subpart KKKK

OAR 340

- 238

- 0060(3)(bbbb) 38

, 39 NO X emission

con centration

or mass limit EU1: 15 ppm dv

(gas) & 42

ppm dv (ULSD)

EU2 & 3: 15

ppm dv (gas) &

42 ppm dv (ULSD) 40

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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 opac ity 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

- 22 6

- 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

, 15 and 16

. At any time that th e 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 s tandard 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

wit h the following:

18.a. O n 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, dur ing 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 EP A 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 testPermit number: 26

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frequency may be weekly.

18.c. The modifi ed 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 da ys following the exceedance. If the results of the daily tests are all less than the standard in Condition 14 , th e test frequency must be the same as before the exceedance occurred.

18.e. If, on a regularly schedule d test day, it is not possible to conduct a n 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 regular ly 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 ac cordance with condition 31

.

20. Applicable Requirement: The permittee must not cause or allow the emissions of Particulate Matter (PM), PM 10 or PM 2.5 from each combustion turbine stack to exceed: [NSR/PSD p ermit 26

- 0235 BACT]

20.a. For EU1, 23.6 lb/hr while burning natural gas, and 42.3 lb/hr while burnin g 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 burnin g 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 ppm dv while burning natural gas, and 5.5 ppm dv while burning ULSD; corrected to 15% oxygen, 3

- hour rolling average

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

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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 ppm dv while burning na tural gas, and 9.0 ppm dv while burning ULSD; corrected to 15% oxygen, 3

- hour rolling average

. 22.b. For EU2 and EU3, 6.0 ppm dv while burning natural gas, and 6.0 ppm dv 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 mu st 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 ppm dv while burning natural gas, and 5.0 ppm dv while burning ULSD ; 3

- hour rolling average

. 23.b. For EU2 and EU3, 3.5 ppm dv while burning natural gas, and 5.0 ppm dv 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. Applica ble Requirement: The permittee must not cause or allow the emissions of carbon dioxide ( CO 2 ) 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/M Wh (gross), 365 day rolling average.

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

Monitor in accorda nce 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 CO 2 CEMS in accordance with 40 CFR Part 60, Appendix B, Performance Specification 3 (PS3);

25.b. Monitor the daily MWh (gross) prod uced by each combustion turbine (N ote: 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 CO 2 per MWh (gross) from combustion turbines EU1, EU2

and EU3; and

25.d. Calculate the 365 day rolling average pounds of CO 2 per MWh from the daily emissions.

26. Applicable Requirement: The permittee must control emissions of sulfuric acid mist (H 2 SO 4 ) from emission units EU1 through EU3 by utilizing good combustion pra ctices and only combusting natural gas and ULSD. [NSR/PSD permit 26

- 0235 BACT ]

Monitor in accordance with condition 31

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

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 no t a violation of this condition unless the permittee s imultaneously 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 t he 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. I ndividual 2 cold starts must not exceed 4.5 hours;

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

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

27.d.iv. I ndividual shutdowns must not exceed 15 minutes;

27.d.v. T otal 3 startup time must not exceed 304 hours in any rolling 12 mo n th period ; and

27.d.vi. T otal shutdown time must not exceed 17 hours in any rolling 12 mo n th period

.

27.e. For EU2 and EU3,

27.e.i. I ndividual 2 startups must not exceed 10 minutes per tu rbine;

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

27.e.iii. T otal 3 startup time must not exceed 167 hours per turbine in any rolling 12 month

period; and

27.e.iv. T otal 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. “H ot 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 comp leted;

27.f.ii. “W arm 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. “C old start” means starting of a combustion turbine when more than 48 hours have

passed since the unit finish ed being shut down;

27.f.iv. “S tartup” means the period commencing when fuel is fi rst fired in the combustion

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

and

27.f.v. “S hutdown” means the period commencing when normal operations cea se 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

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28. Monitoring and Recordkeeping Requirement The permittee must monitor and record the following for EU1, EU2 and EU3 (combustion turbines):

28.a. T he duration of each individual startup;

28.b. T he duration of each individual shutdown;

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

28.d. T he number of shutdowns each month;

28.e. T he total startup time in each rolling 12 month peri od; and

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

O wner 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, EU 2 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 su pply 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 i n 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 followi ng 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 an d 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. T he start and stop times and the duration of each period of ULSD use in each turbine.

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

31.e. T he reasons for using ULSD.

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

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

entities ; or 31.f.ii. K eep records demonstrating extreme price volatility in day to day spot prices for the

gas pipeline that supplies the facility.Permit number: 26

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32. Applicable Require ment: The permittee must limit ammonia slip as follows: [OAR 340

- 226

- 0120(1)]

32.a. From EU1, to no more than 5 ppm dv at 15 percen t O2 based upon a 3

- hour block average. 32.b. From EU2 and EU3, to no more than 5 ppm dv at 15 percen t O2 based upon a 3

- hour block

aver age.

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

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NSPS Subpart KKKK

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

- cycle combustion

turbine ) and simple

- cycle combustion turbine s EU2 and E U3, 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, shutd own, or malfunction in the operation of EU1 through EU3 ; [40 CFR 60.7(b)]

NSPS KKKK SO 2

36. Applicable Requirement The permittee must meet one of the following emission limits for SO 2 from EU1 (combined

- cycle combustion turbine ) and EU2 and EU3 (simple

- cycle combustion turbine s): [40 CFR 60.4330(a)(1) and (2)]

36.a. D o not cause to be discharged into the atmosphere any gases which contain SO 2 in excess of 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt

- hour (lb/MWh)) gross output; or

36.b. D o not burn any fuel which contains total potential sulfur emissions in excess of 26 ng SO 2 /J (0.060 lb SO 2 /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 SO 2 /J (0.060 lb SO 2 /MMBtu) heat input.

37.a. If the permittee selects the monitoring option, m onitoring 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 sam

pling 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 de livery 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 characteristi cs 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 fo r natural gas used is 20 grains of sulfur or

less per 100 standard cubic feet

.Permit number: 26

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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 combust ing natural gas;

38.b. 42 ppm at 15 percent O2 or 160 ng/J of useful output (1. 3 lb/MWh) while combustin g 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 turbine s) 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) w hile 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 du ring 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 turbine s) in accordance with this condition:

40.a. The CEMS must consist of a NOx monitor and a diluent gas (oxygen (O 2 )) or carbon dioxide ( CO 2 )) 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 megawatt

hour (lb/MWh), and

40.a.iii. M ass 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 requ irements 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 (NO x ) ppmdv at 15% O 2 , lb/MMBtu, lb/MWH, and

lb/hr 30 Day Rolli ng*

EU2 and EU3 Nitrogen Oxides (NO x ) ppmdv at 15% O 2 , 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

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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 tes t audit (RATA) of

t he 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 recordin g) 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 NO

x concentration correct ed to 15% oxygen must be calculated for all turbines as

follows:

CC NOx = C NOx x 5.9/(20.9

- %O 2 )

Where:

CC NOx = Hourly average NO

x concentration, ppm (corrected)

C NOx = Hourly average NO

x concentration, ppm (uncorrected)

%O 2 = Hourly average %O 2 by volume in flue gas

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

follows:

M NOx = ER NOx x HI g

Where:

M NOx = Hourly mass of NO

x emissions, lb/hr.

ER NOx = NO

x emission rate in lb/MMBtu as measured by the CEMS

HI g = 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 = (NO

x ) h * (HI) h /P

Where:

E = Hourly NO X e mission rate, in lb/MWh (NO X ) h = Hourly NO X e mission rate, in lb/MMBtu (HI) h = Hourly heat input as determined i n accordance with Condition 45 and equation D

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

P = (Pe) t + (Pe)

c + P S + PoPermit number: 26

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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 10 6 Btu/MWh

Where:

Ps = Useful thermal energy of the steam, measured re lative 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 10 6 = 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 NO

x CEMS meet the equipment, insta llation and

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

40.b.vii. The permittee must ensure that all NO

x 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 NO x 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

c alibration, 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

combin ed 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 NO

x CEMS to acquire the minimum number of data

points comprising a valid ho ur, 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, Sub part 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 requi rements of this paragraph by implementing the QA program and plan described in section 1 of appendix BPermit number: 26

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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 O 2 , 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

elem ents 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% O 2 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 combust ion 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 :

CC CO = C CO x (20.9

– 15)/(20.9

- %O 2 )

Where:

CC CO = Hourly average CO concentratio n, ppm (corrected to 15% O 2 )

C CO = Hourly average CO concentration, ppm (uncorrected)

15 = Oxygen correction level (%)

%O 2 = Actual stack gas oxygen concentration (%) measured by the oxygen

CEMS

41.b. Mass emissions of CO from the combustion turbines/duct bu rners must be recorded each clock hour that the combustion turbines are operating using the following equation :

M co = C co /10 6 x MW co /385 x F d x 20.9/(20.9

- %O 2 ) x HI

Where:

M co = Hourly mass of CO emissions, lb/hr

C co = Hourly average CO concentration, ppm (uncorrected)

1/10 6 = Conversion from ppm to a fraction

MW co = Molecular weight of CO = 28 lb/lb

- mole

385 = Dry standard cubic feet per lb

- mole at 14.7 psia and 68 

### ° F

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

for oil [EPA Method 19]

%O 2 = 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 p er 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 p eriod, excluding periods of startup and shutdown.Permit number: 26

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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 turbine s) using the NOx CEMS req uired 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 rate s 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 turbine s), use the calculated hourly average

emission rates to calculate emissions in ppmd v or lb/MWh on a 4

- hour rolling average basis. [40 CFR 60.4350(g)]

42.d. For EU1 (combi ned

- 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 turbine s):

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 pe r 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 turbine s; 42.f.iii. Corrected 4

- hour rolling NOx emission rates in ppmdv for EU2 and EU3 (simple

cycle combu stion turbine s);

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 h ourly average for all combustion turbine s; 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

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43. Reporting Requirement: T he 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

emiss ions units EU1 (combined

- cycle combustion turbine ) and EU2 and EU3 (simple

- cycle combustion

turbine s), 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 o f

the following parameters are either missing or invalid: NOX concentration, CO 2 or O2 concentration, fuel flow rate, steam flow rate, steam temperature, steam pressure, or megawatts. The steam flow rate, steam temperature, and steam p ressure are only

requ ired 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 reporti ng period and CMS downtime for the reporting period is less than 5 percent of the total operating time for the reporting period, on ly the summary report form must be submitted and the excess emission report need not be submitted unless requested by DEQ.

43.d.ii. I f 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 re porting 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 conversi on 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 syst em was inoperative except for zero andPermit number: 26

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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 b e 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 Su bpart KKKK or TTTT, whichever applies, t he permittee must comply with the relevant Subpart KKKK or TTTT CO 2 standards as applicable to EU1, E U2 and EU3, including all applicable performance testing, recordkeeping and reporting requirements . [40 CFR Part 6 0, 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 pro cedures 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 SO 2 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 SO 2 emissions using the following equation:

M SO 2 = 2.0 x M ULSD x %S ULSD /100

Where:

M SO 2 = Hourly mass of SO 2 emitted from combustion of ULSD, lb/hr.

M oil = Mass of ULSD consumed per hour, lb/h r. %S oil = Percentage of sulfur by weight measured in the sample in accordance with

Condition 37

. 2.0 = Ratio of lb SO 2 /lb S.

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

to calc ulate the SO 2 emissions using the following equation:

M SO 2 = (2.0/7000) x GAS rate x S gas

Where:

M SO 2 = Hourly mass of SO 2 emitted from combustion of natural gas, lb/hr.

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

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

. 2.0 = Ratio of lb SO 2 /lb S.

7000 = conversion of grain/100 scf to lb/100 scf.Permit number: 26

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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:

W CO 2 = (F

c x H x U 1 x MW CO 2 )/2000

Where:

W CO 2 = Daily mass of CO 2 emitted from combustion, tons/day

F

c = Carbon based F

- factor = 1040 scf/MMBtu for natural gas; a site specific F

factor shall be derived for ULSD

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

U 1 = 1/385 scf CO 2 /lb

- mole at 14.7 psia and 68 

### ° F

MW CO 2 = Molecular weight of carbon dioxide (44 lb/lb

- mole)

47.a. The permittee must ensure that each NO x CEMS and component thereof is capable of accurately measuring, recording and reporti ng 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 NO x CEMS, including the automated DAHS, that significantly affects the ability of the system to measu re or record the NO

x emission rate, the permittee must recertify the NO

x CEMS or component in accordance with 40 CFR 75.20(b).

47.c. The permittee must operate, calibrate and maintain each NO

x CEMS used under the Acid Rain Program according to the quality assura nce 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 line arity 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 a n out

- of

- control period occurs to a monitor or NO

x 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 NO x emissions rate data has not b een 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 exc ess 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. Mo nitoring 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

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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 f uel ; 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 perfo rmed 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 RA TA 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 limit s in condition s 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 condition s 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

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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 i s at minimum operating load.

49.a.ii. After the initial test, testing must be conducted annually as specified below , and a t 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 1 st test. A and B Subsequent

tests Su bsequent annual tests must be conducted on the same schedule as

the 1 st through 5 th 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

Fu ll 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 wit h 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 te st 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, E U2 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 thanPermit number: 26

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180 days after init ial startup of such facility on that fue l

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

mo nths 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 operati ng 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 accord ance 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 follo wing:

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 fue l

. 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 tes ts 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 t he 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 (9 0 percent of maximum turbine

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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 03 9 . 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

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Auxiliary Boiler (EU5) Requirements

Applicable Requirement C ondition

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 N otification 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/ PM 10 /PM 2.5 Good combustion practices and natural gas 59 NA

64 SO 2 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 fr om 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 require d 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 fuelPermit number: 26

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being burned in the auxiliary boiler on a monthly basis as required by condition 59.a.i i . 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 o f 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, shutdo wn, 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 emissi ons. [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 duratio n 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 SO 2 or PM standards in 40 CFR Part 60 Subpart Dc provided that only natural gas is comb usted 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 emission s 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 m ust 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

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62. Appl icable 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 accor dance with condition 69

.

63. Applicable Requirement The permittee must control emissions of PM, PM 10 and PM 2.5 from EU5 by utilizing good combustion practices and the use of natural gas. [BACT limit, OAR 340

- 224

- 0070(1)].

Mon itor in accordance with condition 59

.

64. Applicable Requirement The permittee must control emissions of SO 2 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 CO 2 /MMBtu on a 3

- hour block average , excluding period s 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 acco rdance 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 o perated 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 re ported as methane ; and

69.b.iv. CO 2 , 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

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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, E U6

, 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 fil l 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

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

71. DEQ acknowledges that insi gnificant 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 co mply 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% CO 2 or 50% excess air for fuel burning equipment)

71.c. OAR 3 40

- 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 complia nce 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. E mi ssion 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%

CO 2 NA 71

BACT 73 NOx, CO, VOC,

H 2 SO 4 , 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

60.42 07(b) 79 Fuel sulfur

content 15 ppm max NA 80Permit number: 26

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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 th e requirements below for the emergency fire pump engine, EU7: [NSR/PSD permit 26

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Pollutant Requirements

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

Utilize l ean burn combustion, good combustion practices, turbocharging a nd aftercooling.

CO Utilize g ood combustion practices.

VOC Utilize g ood combustion practices.

H 2 SO 4 Utilize ULSD fuel and g ood combustion practices.

PM 10 and PM 2.5 Utilize ULSD fuel and g ood combustion practices.

GHG Utilize energy efficient engine, a nd do not cause or allow emissions of CO 2 to exceed

163 lb CO 2 /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 Condit ion

71 , subject to all applicable requirements. It is subject to NSPS, Subpart IIII, Standards of Performance for Stationary Ignition Internal Combustion Engines. [40 CFR 60.420 0

– 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, own ers 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 cond ition 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

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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 engi ne 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 re garding

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. Monit oring Requirement: The permittee must monitor compliance with condition 79 by performing the monitoring required by condition 37

.

81. Applicable Requirement The permitt ee 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 permitt ed 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 n ot 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 mee t 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 conditi ons 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 go vernment, 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 approv al 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 thatPermit number: 26

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

be yond 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 ma intenance 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 acc ordance 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

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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) Emi ssion Reduction Credit (tons/yr)

PM 198 0 0

PM 10 198 0 0

PM 2.5 198 0 0

SO 2 39 0 0

NO

x 227 0 0

CO 643 0 0

VOC 212 0 0

H 2 SO 4 1 9 0 0

GHG ( CO 2 e) 2,730 ,000 * 0 0

* Rounded to the nearest 1,000

85. The netting basis will be reduced in accordance with the f ollowing: [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 t his 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 i ssued , 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 th e 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

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

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 = P

eu x EF

eu x K

Where:

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

P

eu = Process parameter identified in the table below;

EF

eu = Emission factor identi fied 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 Through

p ut Units Emission Factors

- lb/ [ throughput unit ]

Operating

Mode PM 10 /

PM 2.5 SO 2 NO X CO VOC H 2 SO 4

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 20.8 735.8 122.5Permit number: 26

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Emission Factor Table, continued

Emission

Sour ce
and

Fuel Through

put Units Emission Factors

- lb/ [ throughput unit ]

Operating

Mode PM 10 /

PM 2.5 SO 2 NO X CO VOC H 2 SO 4

EU2 & EU3 simple cycle

combustion

turbines

Natural gas normal [ MMBtu ] 0.011 Acid Rain

Calculations CEM CEM 0.0045 0.0015

start up [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

shutdo wn [event]

0.44 0.06 8.77 10.38 0.36

EU5 auxilliary

boiler Natural gas [MMBtu] 0.0050 0.00 15 0.035 0.040 0.0050 negligible

EU6 ULSD storage tank Constant
[Year] 780

aggregate insignificant

emissions Constant Constant

[Year] 2000 2000 2000 2000 20 00 1400

NOx

86.b. The permittee must ca lculate the rolling 12

- month NOx emissions by summing the

following:

86.b.i. A ll of the hourl y mass emissions during the 12

- calendar month period from each

turbine measured in accordance with Condition 40 ; and

86.b.ii. T he 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

- mont h CO emissions by summing the following:

86.c.i. A ll of the hourl y mass emissions during the 12

- calendar month period from each

turbine measured in accordance with Condition 41 ; and

86.c.ii. T he monthly emissions during the 12

- c alendar month period from the auxiliary boiler

as determined in accordance with Condition 86.a

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GHG

Fuel Throughput Units Emission Factors (lb/throughput unit)

CO 2 CH 4 N 2 O

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 month ly GHG emissions by adding the following:

86.d.i. T he sum of all of the CO 2 hourly mass emissions during the calendar month period

from each turbine measured in accordance with Condition 47 ; 86.d.ii. T he monthly CH 4 and N 2 O emissions from each turbine, as determined in accordance

with the formula in Condition 86.a and th e emission factors above ; and

86.d.iii. T he monthly CO 2 , CH 4 and N 2 O emissions from the auxiliary boiler, as determined in

accordance with the formula in Condition 86.a and the emission factors above.

Rolling 12

- month GH G emissions

86.e. The permittee must calculate the rolling 12

- month GHG emissions as follows:

86.e.i. Sum the monthly CO 2 , CH 4 and N 2 O emissions, as determined in accordance with

condition 86.d , for the 12

- calendar month per iod;

86.e.ii. Convert the mass emissions of CO 2 , CH 4 and N 2 O to CO 2 e using the global

warming potentials (GWP) below; and

GHG gas GWP

CO 2 1

CH 4 21

N 2 O 310

86.e.iii. Add the CO 2 e results together to determine compliance with the PSEL for GHG.

86.f. The emissions factors listed i n 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 b e 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 permi ttee 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 mus t be used for determining compliance with the PSEL in

accordance with condition 86

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GENERAL TESTING REQU IREMENTS

87. Unless otherwise specified in this permit, the permittee must conduct all testing in accordance with DEQ’s

So urce 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 accor dance 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 requ ire 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 ra te 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 max imum 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 A ND RECORDKEEPING REQ UIREMENTS

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

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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 REQUIREMEN TS

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 emissio ns 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 emis sions 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 inc rease 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 hol idays, 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 conti nue 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 logPermit number: 26

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with the semi

- annual and annual monitoring reports. The permittee is only required to submit

a brief sum mary 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 deviation s 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 Divi sion

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 sh utdowns 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 NO

x 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 bein g 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 downtim e 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 ( CO 2 e) is greater than o r equal to 2,756 tons (2,500 metric tons), the permittee must register and report its greenhouse gas emissions with DEQ i n accordance with OAR 340

- 215.

102. <reserved, future Title V condition or reference>Permit number: 26

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STANDARD ACDP REQUIR EMENTS AND GENERAL CONDITIONS

103. REPORTING REQUIREMEN TS

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 3 40

- 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 a n 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 REQUI REMENTS

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 acti vity 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

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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

assesse d 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 Avenu e Portland, Oregon 97204

- 1390

106. GENERAL CONDITIONS A ND 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 e missions 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 rela ted 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

maintenanc e.Permit number: 26

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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 infringem ent 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 fo r 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 Operatin g 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 r equirement 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 9 7201

503

- 229

- 5263Review Report/Permit No.: 26

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### 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 (P art 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 r eport (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 yesReview Report/Permit No.: 26

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TABLE OF CONTENTS

PERMITTEE IDENTIFICA TION

................................ ................................ ................................ ................................ 4

FACILITY DESCRIPTION

................................ ................................ ................................ ................................ .......... 4

NEW SOURCE REVIEW (N SR) AND PREVENTION O F SIGNIFICANT DETERI ORATION (PSD)

.................. 9

BACT DETERMINATION

................................ ................................ ................................ ................................ ......... 12

FINAL BACT DETERMINATIONS AND A MMONIA LIMIT

................................ ................................ ............... 18

AIR QUALITY ANALYSIS

................................ ................................ ................................ ................................ ....... 23

EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECO RDKEEPIN G

....................... 24

PLANT SITE EMISSION LIMITS

................................ ................................ ................................ ............................. 29

HAZARDOUS AIR POLLUT ANTS

................................ ................................ ................................ .......................... 31

C OMPLIANCE HISTORY

................................ ................................ ................................ ................................ ......... 31

SOURCE TEST RESULTS

................................ ................................ ................................ ................................ ......... 31

PUBLIC NOTICE

................................ ................................ ................................ ................................ ....................... 31Review Report/Permit No.: 26

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LIST OF ABBREVIATIONS USED IN THIS REVIEW REPORT

AQMA Air Q uality M anagement A rea ASTM American S o ciety of Testing and

Materials

BDT b one dry ton

CEMS c ontinuous emissions monitoring

system
CFR Code of Federal Regulations

CH 4 methane (greenhouse gas)

CI compression ignition

CMS c ontinuou s monitoring system

CO c arbon monoxide

CO 2 e carbon dioxide equivalent

COMS c ontinuous opacity monitoring

system DEQ Oregon Department of

Environmental Quality

dscf dry standard cubic feet

EF e mission factor

EPA United State Environmental

Protection Agency

EU e missions unit

FCAA Federal Clean Air Act

FGR flue gas recirculation

GHG greenhouse gas gr/dscf grains per dry standard cubic feet

HAP h azardous air pollutant

ID i dentification code

I&M i nspection and maintenance

MB m aterial balance

Mlb 1000 pounds

MM m illion

N 2 O nitrous oxide (greenhouse gas) NA n ot applicable

NESHAP National E mission S tandard for

H azardous A ir P ollutants

NO

x o xides of nitrogen

NSPS New S ource P erformance S tandard

NSR New S ource R eview

O 2 o xygen OAR Oregon Administrative Rules

ORS Orego n Revised Statutes

O&M o peration and maintenance

Pb l ead

PCD p ollution c ontrol d evice

PEMS predictive emissions monitoring

system

PM p articulate matter

PM 10 p articulate matter less than 10

microns in size

PM 2.5 particulate matter less than 2.5

microns in s ize

ppm parts per million ppmdv parts per million, dry, by volume

PSD Prevention of S ignificant

D eterioration

PSEL Plant Site Emission Limit

RICE reciprocating internal combustion

engine

SO 2 s ulfur dioxide

ST s ource test
ULSD ultra

- low sulfur distillate

V E v isible emissions

VMT v ehicle mile traveled

VOC v olatile organic compoundReview Report/Permit No.: 26

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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/unclassifi ed 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 a fter construction is completed.

1.c. This facility is also subject to Title V permitt ing 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

- 2 1 8

- 012 0(1)(f), this review report is intended to provide the legal and factual basis for the draft permit conditi ons. 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 an d 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 IDENTIFICA TION

3. Troutdale Energy Center ( TEC ) proposes to construct and operate a 653 megawat t (MW) electric generating plant in Troutdale , Oregon . T EC proposes to generate electricity with three natural gas

- fired turbin es , one of

which will be a combined

- cycle unit with duct burner and heat recovery steam generator. U ltra

- low sulfur

distil late (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 aluminu m 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 p ower 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, whi le others increase or decrease their output to match the variations in demand. In addition to changes in demand, the availab ility of wind power also adds variability

to the supply of power because wind turbines can only produce power when the wind is blowi ng, 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. A s such , this plant is expected to change its power output frequently

. P ower 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 genera tors 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 curtai lment may occur during very cold winter conditions. During natural gas curtailment periods, industrial facilities and power plants such as TECReview Report/Permit No.: 26

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that can burn ULSD switch to ULSD to help ensure adequate natural gas for home heating and other critical

uses. T he 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 co mbustion turbine generators

. A simple

- cycle combustion turbine generator consists of a combustion turbine that powers an electric generator. These turbine s are capable of rapid start

- up to provide r apidly 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 Dura tion 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

Shutdown s 400 9 minutes each 600 11 minutes each Total duration of startups

and s hutdowns, both fuels 330 hours per year per turbine

8. TEC will have one Mitsubishi M501

- GAC combustion turbine in a combined

- cycle configur ation

. A

combined

- cycle combustion turbine generator consists of the following: a combustion turbine engine that

pow ers 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 i s located between the gas turbine engine and the HRSG to provide additional heat for producing steam. This turbin e takes longer to start up than the simple

- cycle turbines

and will normally run for extended periods of tim e, 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 eac h

Shutdown s 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 f ollowing 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

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10. TEC’s application includes the following summary of emissions from all of the air pollutant emit ting units:

Emissions Summary (Including Startup/Shutdown) , tons per year 1

Equipment NOx CO PM 10 2 PM 2.5 S O 2 VOC H 2 SO 4 HAP CO 2 e (GHG) CO 2

One

Combined

Cycle

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 Simple

Cyc le

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 Neg 3 0.1 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 PM 10 3) N egligibleReview Report/Permit No.: 26

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EMISSIONS UNIT AND POLLUTION CONT ROL DEVICE IDENTIFICATION

11. The emissions units at th is facility are the following:

Emissions Unit

Identification Emissions Unit Description Emission

Control Device

Identification Emission Control Device

Description

EU1 Mitsubishi M501

- GAC

combustion tur bine, 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 fo r 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 Auxili ary 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, ex cluding 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 p ipe 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

 O ffice activities

 Food service activities

 Janitorial activities

 Personal care activitiesReview Report/Permit No.: 26

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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

 Main tenance 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

T itle 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 ass ociated 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 tan ks

 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 anticip ated 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 mot ors

 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 sto rage 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

 Emissi ons 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 traini ng

 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 entrainme nt 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 startupReview Report/Permit No.: 26

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Final Application number: 027060 Page 9 of 31

NEW SOURCE REV IEW (NSR) AND PREVENTION OF SIGNIF ICANT 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 facilit y 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

PM 10 19 8 15

P M 2.5 19 8 10

NOx 2 22 7 40

CO 64 3 100

SO 2 3 3 6 40

VOC 4 21 2 40

H 2 SO 4 (sulfuric acid mist) 1 9 7 GHG (CO 2 e) 2,7 30,000 75,000

CO 2 2,724,963 1 100 1) Not including aggregate insignificant emissions

2 ) NOx is regulated as NOx itself, and also as a precursor to both ozone and PM 2.5

. 3 ) SO 2 is regulated as SO2 itself, and also as a precursor to PM 2.5

. 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 wil l 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 classifi ed as a Federal Major Source because emissions of CO will e xceed 250 tons per year and

GHG and CO 2 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 Fed eral M ajor 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. PM 10 ; 16.b. PM 2.5 ; 16.c. NOx (as NOx and as a PM2.5 precurso r);

16.d. H 2 SO 4 ; and

16.e. GHG

17. The facility is not subject to either NSR or PSD for SO 2 as itself or as a PM 2.5 precursor because the emissions

are less than the SER.

NSR Requirements

18. Within the Portland Maintenance Area, the requirements specified in OAR 340

- 224

- 0 060(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

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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. T he re quirement for BACT applies to e ach emissions unit that emits the maintenance pollutant or precursor(s)

.

19.b. The applicant perf ormed 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 avail able, 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 Ne t 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 Main tenance Area of 227 tons/year NOx, 212 tons/year VOC and 643 tons/year CO.

The allocations a r e sufficie nt 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 acc ordance 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. Th e 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 se ction, 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 PM 10 , PM 2.5 , NOx (as NOx and as a PM2.5 precursor),

H 2 SO 4 , and GHG the requirements spe cified in OAR 340

- 224

- 007 0(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

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Final Application number: 027060 Page 11 of 31

24.a. Best Available Control Technology (BACT). The owner or operator must apply BACT for each

maint enance 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. T he requirement for BACT applies to e ach emiss ions 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 owne r or operator must provide an air quality analysis in accordance with OAR 340

- 225

- 0050 through 340

- 225

- 007 0. (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 me et 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 precu rsor 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 we re 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 s ource 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 wit h 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 modif ication 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 concentration s listed in the ruleReview Report/Permit No.: 26

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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. Carb on monox ide: 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 t he requested

PSEL.

26.d.ii. Nitrogen dio xide: 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. PM 10 : PM 10 is monitored by DEQ in Portland at SE 57th and Lafayette and the data is considered representative of the proposed location for this facil ity. In addition, the applicant modeled less than the significant monitoring concentration.

26.d.iv. PM 2.5 : PM 2.5 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 : O zone 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 c over 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 technolog y that must be used to achieve the emission limit, and is often referred to as “top

- down BACT” because the analysis cons iders 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 oth er 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 effectiv e 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 techno logies 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 oth er costs, and document results Step 5

– Select BACTReview Report/Permit No.: 26

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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 turbi nes; auxiliary boiler; emergency fire pump engine ; cooling towers

GHG Combustion turbines; auxiliary bo iler ; 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

Pollut ant Control technology review ed

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 selectiv e catalytic reduction (SCR) with aqueous ammonia injection at all times except during startup and shutdown; Limit the time in startup or

shutdown. 2.0 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during startup and shutdown.

5. 5 ppm dv 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 Catal ytic Oxidation (CatOx)

Catalytic Combustion (XONONTM)

DLN Burners

SCONOXTM Oxidation catalyst ; Limit the time in startup or

shutdown. 3.3 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during startup and shutdown. 9.0 ppm dv 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

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Pollut ant Control technology review ed

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 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during startup and shutdown. 5.0 ppm dv at 15% O2, 3

- hr rolling averag e 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.

H 2 SO 4 Utilize only natural gas or

ULSD fuel. None

PM 10 and

PM 2.5 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 st art.
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

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Final Application number: 027060 Page 15 of 31

30.b. EU2 and EU3

GE LMS

- 100 combustion turbines, simpl e 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 inj ection

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 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during startup and shutdown. 3.8 ppm dv 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 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during startup and shutdown. 6.0 ppm dv at 15% O2, 3

- hr rolling averag e 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 ; Li mit the time in startup or

shutdown. 3.5 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during startup and shutdown. 5.0 ppm dv at 15% O2, 3

- hr rolling average when combusting ULSD, except during startup and shutdown. Startup time s limited to: 10 minutes for any startup.

Shutdown time limited to 11

minutes.

H 2 SO 4 Utilize only natural gas or

ULSD fuel. NoneReview Report/Permit No.: 26

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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

PM 10 and

PM 2.5 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 star tup
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 fuel s 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

PM 10 and

PM 2.5 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

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Pollutant Control technology reviewed

by applicant Control technology proposed by applicant Emission limit(s) proposed by applicant

VOC Util ize Low

- NOx burners and

FGR. 0.005 lb/MMBtu , 3

- hr block

average , except during startup

and shutdown.

H 2 SO 4 Good combustion practices; Utilize only natural gas. None

PM 10 and

PM 2.5 Good combustion practices; Utilize only natural gas. None

GHG Carbon c apture 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 te chnology 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.

Po llutant 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 practice s. None

H 2 SO 4 Utilize ULSD fuel;

Good combustion practices. Utilize ULSD fuel; Good combustion practices. None

PM 10 and

PM 2.5 Utilize ULSD fuel;

Good combustion practices. Utilize ULSD fuel; Good combustion practices. None

GHG High efficiency engine Hig h efficiency engine 163 lb CO2/MMBtuReview Report/Permit No.: 26

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FINAL BACT DETERMINA TIONS 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 du ct burner) and EU2 and EU3 (simple cycle combu stion 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 (co oling towers, auxiliary boiler, ULSD storage tan k, and fire water pump engine), which are summarized above in paragraphs 30.c through 30.f

. ; and

31.c. Other requirements an d 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 t hat contributes to the formation of ozone. NOx levels in the Portland area are generally well below the National Ambie nt Air Quality Standards for NO 2 , but NOx contributes to nitrogen deposition in national forests and the Columbia River Gorge National Sce nic 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 c ontrol 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 t he catalyst they react to

convert NOx and ammonia (NH 3 ) into nitrogen gas (N 2 ) and water (H 2 O) . 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 e mitted. Ammon ia 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 limi t ammonia slip to 5 ppm on a three

- hour average basis. Compliance with this limit must be demonstrated by e missions 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 emissio ns will go above the numeri cal 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 establ ishing 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 avera ge . The NPS provided examples of facilities that had one

- hour avera ge 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 appropria te for combustion turbines that operate asReview Report/Permit No.: 26

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Final Application number: 027060 Page 19 of 31

base

- load generators which operate predomin antly at relatively steady power outputs , but a re not appropriate for this facility because it is intended to operate with freque ntly changing output to meet changing dem and or to fill in for changing wind power supply

.

38. DEQ understands that this facility will be used to integrate with p ower generated by wind turbines which have a variable output due to (sometimes unpredictable) chan ges in the wind, and agrees that this f acility 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 ex tra fuel over the amount required to run at s teady

- state at the higher power output, which also increases NOx production in the turbine. The NOx emission control sy stem will react to increased NOx by increasing ammonia injection, but there is a short time lag before the control system reacts, resulti ng 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 applic ant 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 ppm dv on a th ree

- hour block average basis, with annual testing to show compliance with the limit. Lower ammonia limits have been established for other facilities, but th ese 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 t he 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 i t 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. D uring 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 al so 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 lo ad changes that this facility will ex perience and the use of ULSD

, DEQ a grees with the GHG limits proposed by the applicant

.Review Report/Permit No.: 26

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Proposed BACT and Ammonia Summary

42. The proposed BACT limits are summarized in the tables below:

42.a. EU1

Mitsubishi M501

- GAC combus tion 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 na tural 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 ppm dv at 15% O2, 3

- hr rolling av erage when combusting natural gas, except during startup and shutdown. 5.5 ppm dv at 15% O2, 3

- hr rolling average when combusting ULSD, except during startup and shutdown. Startup 1 times limited to: 4.5 hours for a cold start; 1.5 hours for a warm start; an d

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 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during start up and shutdown. 9.0 ppm dv 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 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during startup and shutdown. 5.0 ppm dv at 15% O2, 3

- hr rolling average when combusting ULSD, except duri ng 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.

H 2 SO 4 Utilize only natural gas or ULSD fuel. None

PM 10 and

PM 2.5 Utilize only na tural 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 minu tes.

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

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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 Propo sed BACT Limits (apply separately to each LMS

100 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

start up and shutdown; Limit the time in startup or shutdown. 2.5 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during startup and shutdown. 3.8 ppm dv at 15% O2, 3

- hr rolling average when combusting ULSD, except during startup and shu tdown. Startup 2 times 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 ppm dv at 15% O2, 3

- hr rolling average when combust ing natural gas, except during startup and shutdown. 6.0 ppm dv 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 Oxidati on catalyst ;

Limit the time in startup or shutdown. 3.5 ppm dv at 15% O2, 3

- hr rolling average when combusting natural gas, except during startup and shutdown. 5.0 ppm dv at 15% O2, 3

- hr rolling average when combusting ULSD, except during startup and shutdow n. Startup times limited to: 10 minutes for any startup.

Shutdown time limited to 11 minutes.

H 2 SO 4 Utilize only natural gas or ULSD fuel. None

PM 10 and

PM 2.5 Utilize only natural gas or ULSD fuel;

Limit the time in startup or shutdown. 9.1 lb/hr total P M (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,

excep t 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 Li mits

PM 10 and

PM 2.5 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

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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.

H 2 SO 4 Good combustion practices;

Utilize only natural gas. None

PM 10 and

PM 2.5 Good combustion practices;

Utilize only natural gas. None

GHG 117 lb CO2/MMBtu , 3

- hr block a verage

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 C I 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

H 2 SO 4 Utilize ULSD fuel;

Good combustion practices. None

PM 10 and

PM 2.5 Utilize ULSD fuel;

Good combustion practices. None

GHG Utilize energy efficient engine 163 lb CO 2 /MMBtuReview Report/Permit No.: 26

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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 NO 2 PM 10 and PM 2.5 Annual

Annual and 24 hour
NAAQS NO 2 PM 10 and PM 2.5 Annual and 1 hour

Annual and 24 hour

Class I area increments NO 2 PM 10 and PM 2.5 Annual

Annual and 24 hour Class I Air Quality Related

Values (AQRV) NOx SOx, including H 2 SO 4 PM 10 Annual and 24 hour

Voluntary AQRV as sessment of the Columbia River Gorge

National Scenic Area NOx SOx, including H 2 SO 4 PM 10 Annual and 24 hour

Oregon Department of Energy Protected Area Analysis (secondary NAAQS) NO 2 PM 10 and PM 2.5 Annual and 24 hour

44. T he air quality ana lysis was review ed by DEQ and approved. T he air quality ana lysis review report is attached to the end of this report.Review Report/Permit No.: 26

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EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECO RDKEEPING

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 n ot 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

availabl e 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 permi t because TEC has agreed to use only natural

gas and ultra

- low sulfur

distillate (ULSD) fuel . The

ULSD has a maximu m 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

comp liance with OAR

340

- 228

- 0110.

Combined

cycle

combustion

turbine 340

- 208

- 0110(2) Visible emissions : no more than three

m inutes in any one hour equal to or greater than 20% opacity.

340

- 208

- 0600 Visible emissions: Do not allow any non

fuel

- burning

- equip ment to discharge any air contaminant that is 20 percent opacity or

great er for more than 30 seconds in any one

hour. Combustion turbines operating without duct

firing are non

- fuel

- burning equipment.

340

- 226

- 0210(1)(b) (non

fuel 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 duct

firing 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

m inutes in any one hour equal to or greater than 20% opacity.Review Report/Permit No.: 26

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Emissions

unit OAR Summary of rule requirement Notes

340

- 208

- 0600 Visible emissions: Do not allow any non

fuel

- burning

- equipment to discharge an y air contaminant that is 20 percent opacity or

great er 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 d oes 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

m inutes in any one hour equal to or greater than 20% opacity.

340

- 228

- 0210 (1)(b) N o 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, 197 0. Fire pump engine 340

- 208

- 0110(2) Visible emissions : no more than three

m inutes in any one hour equal to or greater than 20% opacity.

340

- 208

- 0600 Visible emissions: Do not allow any non

fuel

- burning

- equipment to discharge any air

contaminant that is 20 percent opacity or

great er 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 d oes not a pply 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 p sia) 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 ge nerating units (boilers), 10 to 100 MMBtu/hr. Fire pump engine IIII Standards for stationary compression

ignition internal combustion engines

Combustion

turbines KKKK Standards for stationary combustion turbinesReview Report/Permit No.: 26

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Equipment Part 60 Subpart Description Notes

Combined

cycle

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 UL SD 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 CF R Part 60 Subpart Dc.

50.a. Subpart Dc ( § 60.42 c and § 60.43 c ) does not specify any emission li mits for boilers t hat combustion only natural gas;

50.b. Subpart Dc ( § 60. 48c(g)(1) or (2) ) require s 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 calenda r 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 oper ation 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) spe cify 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 conta ins 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

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52.b.i. 15 ppm at 15 percent O 2 or 54 ng/J of useful output (0.43 lb /MWh ) while combusting natural gas; and

52.b.ii. 42 ppm at 15 percent O 2 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.

NSP S Subpart TTTT

53. Subpa rt 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 CO 2 /MWh on a 12

- opera ting month annual average basis for combined

- cycle combustion turb ine 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 JJJJ JJ , Standards for boilers at area s ources, is not applicable to this facility.

55.a. T he auxiliary boiler is not subject to Subp art 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 w aste heat boilers including duct burners and

heat reco very 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

t urbines 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) st ate 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 S ubpart IIII for compression ignition engines (addressed in paragraph 51 of this report) ; and

57.b. N o 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 appl ication at least 24 months before the date on which theReview Report/Permit No.: 26

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first affected unit commences operation. Under the Acid Rain Program, the permittee will be required to monitor and report SO 2 and NOx emissions from the affected units and obtain allowances equal to their annual

SO 2 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 SO 2

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 SO 2 monitoring requi rement s (condit ions 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 appende d to this permit.

Accidental Release Prevention (Part 68 and Section 112(r) )

59. TEC is not sub

ject 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 system s f or the

combustion turbines. H owever, TEC will use aqueous ammonia solution at a concentration of less than 20 percent and is therefore not subject.

Insignif icant 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

- 2 00

- 0 02 0.

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 li mit 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 o ne 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, nett ing 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) Pre vious (tons/yr) Proposed

(tons/yr)

PM 0 0 198 0 198 198 198

PM 10 0 0 198 0 198 198 198

PM 2.5 n/a 0 198 0 198 198 198

SO 2 0 0 0 0 39 39 36

NO x 0 0 227 0 227 227 227

CO 0 0 643 0 643 643 643

VOC 0 0 212 0 212 212 212

GHG (CO 2 e) 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 pe r year for H2SO4 (and r ounded 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 yea rs for all pollutants listed except GHG and PM 2.5 are 1977/78 or an earlier year. This facility did no t exis t during these baseline years, so the basel ine 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 l isted 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 P SEL 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 r educed 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), provi de 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

em issions 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

- 22 6

- 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 nor mal operation has not yet been achieved.

SIGNIFICANT EMISSION RATE

63. The proposed PSEL is greater than the previou s 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.

Pol lutant 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

PM 10 15/5 * 198 0 198

PM 2.5 10 198 0 1 98

SO 2 40 39 0 39

NO

x 40 227 0 227

CO 100 643 0 643

VOC 40 212 0 212

GHG (CO 2 e) 75,000 2,730,000 0 2,730,000

H 2 SO 4 7 19 0 19

* For PM 10 , the first value is for sources located anywhere in the state other than the maintenance portion of the

Medford

- A shland AQMA

. In the Medford

- Ashland Maintenance Area , the SER for PM 10 is 5 tons/yr.Review Report/Permit No.: 26

- 0235

- ST

- 01

Final Application number: 027060 Page 31 of 31

HAZARDOUS AIR POLLUT ANTS

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 emitt ed, 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 Combusti on 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 tu rbines, 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 publi c notice until 5:00 pm, October 14, 20 13 . DEQ he ld a public hearing on the draft permit on October 3

. After the comment period and heari ng, DEQ revie w ed the comments and modified the permit as discussed in the response to comments. The per mit 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 hea vy 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 megaw atts (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 gener ator (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 simp le

- 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

emissi ons 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 Mi tsubishi M501

- GAC turbine, with a heat

- recovery steam generator (HRSG) equipped with the capability of duct firing. Natural gas will be the prim ary fuel for the

combined

- cycle power plant; however, during times of natural gas curtailment, the unit will b e 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 ga s 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 prop osed 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 th ree 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 t he a dual

fuel 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, PM 10

, PM 2.5 , SO 2 , and VOC

are shown in Table 1. A nnual estimates assume 8,760 turbine operating hours, with 720 hours designated for ULSD and 321 hours de signated to startup/shutdown emissions.

Table 1

. Maximum Potential Emissions Estimates

SO 2 emissions were under the Significant Emissions Rate (SER) and no additional analysis was required. F acility emissions of CO and VOC were offset by available g rowth allowance s identified in the
Portland Area Carbon Monoxide and Ozone Maintenance Plan s , a nd a modeling analysis of CO and
VOC was also not required.

Since PM 10 , PM 2.5 , and NOx emission levels exceeded the SER , t heir impacts were evaluated in the
S IL dispersion modeling analysis.

The most conservative emissions scenarios were identified in the preliminary analysis. T wenty cases of
different loads and ambient conditions were studied to determine the combination of emissions andMemo 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 PM 10 /PM 2.5 emissions used in the SIL modeling by equipment type and operating scenario. Table 3 shows the maximum pot ential NOx emissions.

Table 2

. Maximum PM 10 /PM 2.5 emissions by equipment type and operating scenario

Short term emissions in grams/second are from the AERMODE input files. NG emissions are from case 11 for combined cycle operation and ca se 8 for simple cycle operation. ULSD emissions are from cases 20 and 18 for combined cycle and simple cycle operation respectively. Annual combined cycle PM 10 / 2.5 emissions are from case 12. Annual Simple Cycle PM 10/2.5 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, 1425.80MMBT u/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, e xit 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 191 F, exit velocity 52 ft/s;Memo to George Davis

2 August 2013 Page 35

Table 3

. Maximum NOx emissions by equipment type and operating scenario

Short term Combined Cycle operation NO2 emissions are from Case 6. Short term simple cycle operation
NO2 emis sions are fro m 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 NO 2 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 Page 36

The combustion turbines and auxiliary equipment were modeled as point sources within AERMOD.

Building Downwash

Building influence s 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 f enceline

- 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

- 5 000m 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 Univ ersal 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 m eteorological 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 stat ion (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 PM 10, 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 backgro und 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 u sing 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 NO 2 were not significant and no additional modeling to demonstrate compliance with NAAQS or Class II increment was required. However, PM 10 and PM 2.5 impacts were greater than their respective SILs and a refined modeling analysis was per formed 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

For annual and 24

- hr PM 10 , annual PM 2.5 , and annual NO 2 , th e modeled concentration is the highest o f the 5

- year averages of the maximum modeled concentration predicted each year. For 1

- hr NO 2 , the average of the 5

- year averages of the maximum modeled concentration predicted each year for all receptors is used as m odeled

concentration in this table. An ambient ratio of 0.75 used to convert annual NOx concentrations to NO 2
concentrations . For 1

- hr NO 2 modeling, NOx emissions were converted to NO 2 emissions using the EPA NO 2 /NOx

ratio of 0.8.

For 24

- hr PM 2.5 , the mo deled concentration is the average of the 5

- year averages of th e maximum modeled concentration predicted each year.

5. Class II Area Analysis: PM 2.5 and PM 10 NA AQS 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 pred icted

under the worst case scenarios described in the Emissions section of this review. The results of PM 10 and PM 2.5 modeled concentrations comparison to NAAQS are shown in Table 5.Memo to George Davis

2 August 2013 Page 38

Table 5

. NAAQS Modeling Results

As shown in the table, the 24

- hr PM 2.5 modeled concentration is the average of the 5

- year averages of the maximum modeled concentration predicted each year. The a nnual PM 2.5 modeled concentration is the highest of the 5

- year averages of the maximum modeled c oncentration 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 PM 2.5 annual modeled concentration used in NAAQS comparison was pr edicted at a Washington receptor, the background concentration from Camas monitoring site was used in calculating the total concentration. The

PM 2.5 24

- hour modeled concentration used in this comparison was predicted at an Oregon receptor, therefore the

ba ckground 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

The 24

- hr PM 2.5 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 NO 2 NAAQS Analysis

The NO 2 competing source analysis showed impacts great er than the 1

- hr NO 2 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 Page 39

Table 7

. Facility contributions to 1

- hr NO2 Modeled Exceedances

7. Class I Are a 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 radiu s of the project site are summarized in Table 8.

Table 8

. Summary of Class I areas within 300 km radius

8. Increment Analysis

Model

CALPUFF Version 5.8 was used to model the annual NOx, PM 10 , and PM 2.5 , and 24

- hour PM 10 and PM 2.5 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 u sed 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 Modeli ng 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

The 24

- hour PM 10 a nd 24

- hour PM 2.5 predicted impacts exceeded their respective SILs at the Mt. Hood

Wilderness area. A 24

- hour PM 10 competing sources impact analysis was completed to demonstrate compliance with Class I PSD Increment. The competing sources analysis included all large PM 10 increment consuming sources within the range of influence for the Mt. Hood Wilderness.

A 24

- hour PM 2.5 competing sources increment analysis was not required since there have been no PM 2.5 PSD sources constructed within the range of influen ce for the Mt. Hood Wilderness since the 2011 PM 2.5 baseline

.

The results of Class I PSD increment analysis are shown in Table 10.

T able 10

. Class I PSD Increments Competing Sources ResultsMemo to George Davis

2 August 2013 Page 41

9. Class I AQRV Analysis

For Air Quality Related Values (AQRV) analysis, t he 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.

Mode l

MMIF

– Beta

CALPUFF

- vers ion 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

concen trations 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 ea ch month was used as a background concentration.

Deposition

Atmo spheric 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 de position 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

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 threshol d 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

conditio ns. 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 1 2. Background Concentrations of Light Attenuating Pollutants

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

Near

- Field Visibility

A near field visibility analysis of the TEC i mpacts 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 vis ibility 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 ResultsMemo to George Davis

2 August 2013 Page 44

10. Columbia River Gorge AQRV Ana lysis

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 crit eria 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 analysi s 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 quali ty 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 cons istent 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

comm ents, and the TEC letter of July.

Table 15. CRGNSA Regional Haze Analysis.

While the 98 th %

- 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 90 th %

- 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 90 th %

- 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 pl ume 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 thanMemo to George Davis

2 August 2013 Page 45

5%), plume contrast (greater than 0.02), blue

- red rati o (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,

wit h 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 vi sibility 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 usi ng 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 max imum reduction of 33.4% at the distance of 1 km only occurred for

1 hour.

Table 16. CRGNSA Plume Visibility Analysis

Using the delta E parameter as the best indicator of plume perceptibility, the PLUVUE results show that

withi n 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 win d 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 e arly evening periods, the maximum delta Es are lower or similar to those shown in Table 16. As a result, although theMemo 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, wit h 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 sign ificance 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 D elta 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 depositio n 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 S tudy and Strategy of 2011 states th at:

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 p ristine 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 haz e plans

.

The str ategy 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 timefram e 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 90 th %tile delta DV was used for comparison against annual background with a target threshold of 1.0, in lieu of the 98 th

%tile with a thresho ld 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 on e 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 hasMemo 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 qua lity analysis of TEC, using the emission rates, stack parameters, unit locations, and operating scenarios as provided in the application, show s that all projected impacts comply with NAAQS and Class II/ Class I Increment Analyses requirements. In additio n, 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 ana lysis 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

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The draft permit for the Troutdale Energy Center was place d on public no tice from September 4 , 2013, through October 14 , 2013. DEQ held a public hearing on October 3 , 2013. A tota l of 181 individuals and organizations submitted comments during the comment period.

Public involvement is an important part of the permit issuance process, and DEQ thank s everyone who commented for their involvement in the process and for their time and effort.

The comments are organ ized 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 Trout dal e 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 app licable 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 c ondition 1 in the draft permit.

Other minor typograp hical 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 b y 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

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Comment s by 177 individuals

Commenters: Submitted by 177 c ommenters who are listed beginning on page 3

.

Summary of comment s : 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 ar eas

. The facility would harm businesses in the Gorge.

A dopt findings that the facility would cause signi ficant 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. T he 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

u ndermine 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 bu sinesses in the Gorge; or would cause signi ficant 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

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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 S wanson 9606 26th Ave NW Seattle, WA 98117

- 2515

Dr. Barbara Manildi 3525 Red Cedar Way Lake Oswego, OR 97035

- 3523 (503) 635

- 4878 Mr. B enjamin I gnatowski

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 W agner 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. Dav id 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

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Ms. Diana Moeller

1918 Harris Ave Richland, WA 99354

- 2340

Ms. Diane Enochson

9921 N Ivanhoe St Portland, OR 97203

- 1419

Ms. Dinda E vans 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. J ane Harold

1515 SW P endleton 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 S now 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 K irchhoff

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 K nipe 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

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- 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

- 640 9

Ms. Lydia Deems

241 Lakeside Dr White Salmon, WA 98672

- 9006

Ms. L ynda Cunningham

5505 E E vergreen 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

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- 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 Ci r 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, O R 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 C ohn

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 G erould

3307 SW Dosch Rd Portland, OR 97239

- 1423 (503) 221

- 7253

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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 L ange 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 Av e 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 G oeckermann Hugo R oad

Grants P ass, 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 G rimstad 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

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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

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Comment s 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 th e Gateway to the Columbia Gorge.

Response : Thank you for your comment.

Comment s by Paul Wilcox

Commenter:

Paul Wilcox

1030 SW 17 th 

### Way Troutdale, OR 97060

Summary of comments: The applicant has chosen the monetary path to offset CO 2 

### 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 vehi cle 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 th e CO 2 

### emissions offset program and the Public Utility Commission regulates utility costs. DEQ has no role in either the CO 2 

### 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 ensurin g that air quality in the entire state meets National Ambient Air Quality Standards. Air quality in the Portland Metro area currently meet s 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 ana lysis and has determined

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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 relat ed to generating capacity

.

Comment s 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 a nd 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 betwe en 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 C enter. 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 installati on 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 kn ow 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?

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5. Lastly, we would like to know the impact of the combustion process air d ischarges. 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 neighborh ood?

Response: Comments 1 through 3 are outside the scope of the air quality permit ting program

.

Regarding c omment 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 loca tions 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 sever al hundred trucks, but the pollution effects of Troutdale Energy Center and several hundred trucks per day pass ing through the neighborhood would be quite different.

Emissions from trucks pa ssing through the neighborhood would occur in close proximity to r esidents

. 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 excee ded. For example, a 1

- hour ambient air quality standard for nitrogen dioxide (NO 2 

### ) was established in recent years by the U.S.

Environmen tal Protection A gency (EPA) and it is generally believed by both EPA and DEQ that the most likely location s for this st andard to be exceeded are near heavily travelled highways.

Regarding the effects of Troutdale Energy Center’s emission s
, DEQ required Troutdale Energy Center to perform a modeling analysis of the facility’s emissions. DEQ reviewed and approved t he analysis results and methodology

.

The analysis look ed 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 Lev els. The analysis indicates that e missions 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 excee dances of the 1

- hour NO 2 

### 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 NO 2 

### 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

p ermit and is available from DEQ.

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Comment s by NEDC, Friends of the Columbia Gorge and Columbia Riverkeeper

Commenters : Air Quality Group, Northwest Environmental Defense Cente r JJ England

Shanna Fricklas Matthew Ring Heather Fossity

Rachel Morris YoungWoo Joh

Erica Nist

- Lund

Friends of the Colum

bia 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 p eriods 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 requireme nt 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 yi elds

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 t o limit the hours of operation on ULSD as part of the BACT determination. DEQ did include lim its 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 p rocesses 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 th at 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 ther eof, may

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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 turbin es for both fuel type s
, with the

except ion of G HGs 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 do es 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, a nd in consideration of comments received, reviewed condition

30

.

Condition 30 in the draft permit stated that t he combustion turbines must burn only natural gas except as

follows:

 The c ombined 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 pe r 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

Commiss ion (PUC), may curtai l 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 contac t ed 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. Curta ilment 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

ar ea are contacted and told to curtail the use of gas. Cu rtailment is not effected by physically shutting off the flow of gas, but by the price pen alty in the interruptible rat e schedule. 1



### DEQ requested Troutdale Energy Center clarify their intentions with respect to the use of ULSD fuel. Troutdale Energy C enter provided the following information on December 23, 2013 :

“ Troutdale Energy Center, LLC (TEC) has requested the ability to use ULSD instead of na tural 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.

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(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 pri ce 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 woul d 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 Analysi s 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.

T he documen t 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.” (pag e 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 .” (page s 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, a nd 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 ULS D in all turbines is consistent with limiting the use of ULSD to only those times when t he natural gas supply is “curtailed”, where DEQ now

under stands 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

.

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DEQ doe s not have expertise in the area of natural gas pric ing 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 n eeds to be specifically allowed.

DEQ has revise d condition 30 in the final permit to state that t he 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 e missions 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 calenda r 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 kee ping 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 a lso 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 port ion 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 startup s and shutdowns, and

 esti mates of the emissions that would occur during those time periods

.

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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 emission s, 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 al so specif

ies the emissions and specifying the emissions also specifies the time. There fore, with regard to startups and shutdowns

, a time limit or an emissions limit are equiv alent 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 jurisdic tions 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 mid

peaking 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 ap ply

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 turbine s 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 diff erent 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 em ission 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 bu rns 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 situati on (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

-

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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 sub stantially 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/sh utdown 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

- 001 4;

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 w indpower 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 appl icant a bout proposed turbine operating scenarios and turbine performanc e and emissi ons under a number of operating

load s.

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 hydro

generation output, the combined

- cycle power plant at the Troutdale Energy Center could also be

load followi ng. The combined

- cycle plant is therefore not comparable to base load resources in

ot her 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 pla nt 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 dimin ish. 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

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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 outp ut 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 fa cility 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 tables 4 

### . 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/h r) 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 reference d in footnotes 1 and 3, but contained errors. Corrected tables were provided by email on December 20, 2013.

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The Proposed BACT : Annual Average values in the first row of each table are the total annual CO 2 

### 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(ton s) ] 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/MW h 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) 2 1,136 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) 2 844 878 884 923 1,311 1,406

Percent increase in CO2

emissions in lb/MWh over full load

-- -- 5% 9%

-- 7%



### T ables 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 load s . However, and perhaps counter

- intuitively, GHG emissions in pounds per megawatt

hour are at their minimum at full load and are higher at low load s

. DEQ understands that all combustion turbines exhibit the same basic performance characteristics; that is, they operate at maximum efficiency at

full load and at lowe r 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 re cognizes 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 BA CT 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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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 va rying 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.

T he fact that wind power is available at times means that , generally, less fuel overall must be burned to generate ele ctricity

. So, w hile an individual generating facility may have to operate in a less efficient manner, the electrical generating system as a wh ole 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 Center 5 

### , Pio Pico Energy Center 6 

### and Puget Sound Energy Fredonia Generating Station Expansion Project 7 

### . 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

combu stion 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) 1,13 6 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 B ACT 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 re lation to wind power

.

5 Referenced on page 17 of this document

6 Reference d on page 18 of this document

7 Referenced on page 18 of this document

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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 combustio n turbines at low loads much of the time. DEQ believe s that setting G HG

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 o perating scenarios in Tables 1 and 2 (on page 18 ) wh ich might reasonably occur in practice and which DEQ believes represent reasonable worst

- case scenario s. T he GHG BACT limits proposed in the draft permit are based on these scenarios and prop erly take into account the higher GHG emission rates (on a lb/MWh basis) at lower loa ds

.

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 ope ration, DEQ notes that t he proposed GHG BACT limits differ significantly from other proposed BACT limits in the draft permit in that the GHG BACT limits are lo ng

- term limits (annual average) as opposed to short

- term limits (averaged over hours). DEQ also notes that t he proposed GHG

BACT limits are based on a reaso nable 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. R ecalculating 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 sepa rate 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 prud ent 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 h as 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 t hese units are not intended to provide baseload power. Nonetheless, the wind

- shaping purpose of these emission units and the lack of

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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:

Conditi ons 47 and 49 are monitoring requirements for CO 2 

### 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 CO 2 

### 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 S ubpart 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

v ersion of whichever rule EPA revises

.

Comment : IV. Conditions 50 and 51 w ill 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 intende d 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

Sour ce 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/c mspolicy.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 sp irit 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 prox y 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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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 T EC 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 equipm ent; 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

d etermining 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 V OC 9 

### and 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 r evised condition 5 0 to require additional testing while using ULSD as follows: Following the initial test, s ubsequent 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 r ecent 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 neede d.

U pon reconsideration of the proposed testing schedule, DEQ has revised condition 51 to require

ad ditional testing while using ULSD as follows: Following the initial test, s ubsequent 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.

Co mment: 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, Comm ercial, 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 visibili ty 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 l ight 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 problem atic 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

im provements 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 w hat 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 th e following:

“While not “zero”, the low and localized levels of TEC’s visibility a n d 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 supportin g 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 t he 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 im pacts 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. ”

Comment s 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 non

profit organization with approximately 5,000 members dedicated to protecting and enhancing the

resources of the Columbia River G orge. 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 th e 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 Qua lity 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.

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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 t hat 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 S ervice 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 prov ide 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 Cle an 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 implementa tion 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 Ar ea (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 inclu ded 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 scen ic 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 c ause 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.

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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 als o 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 th e 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. Frie nds 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] co mpact 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 C enter, 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 a s 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 inc onsistency 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. Inste ad, 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 t he 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 f or 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.

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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 S ervice 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 de tailed 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.

T he 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 Nati onal 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

t o 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

fired plants is completely unrelated to the TEC pro ject 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 improveme nt 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 sho ws 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 t here 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 fac ility. 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 wo uld 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 th at 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 addres s 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 pla nt 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

revi se its staff memoran dum 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 b enefits 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

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ensure compliance wi th 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

f ederal Class I areas, which are pristine wilderness areas and national parks, have been long established by the Environmental Protection Agency an d F ederal Land M anagers
, and are used in the PSD program

. Following DEQ guidance, t hese 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 conclud e d 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 G org e, 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 relie d heavily o n 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. T he Columbia River Gorge National Scenic Area is

not a Class I area , but a mix ed use area with both scenic and urban characteristics

. As noted above, DEQ

consider s 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 effective ness of Best Available Control Technology required by DEQ rule s

. There is however no basis for requiring the us e 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 a n adverse impact as a “r easonable 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 show ed 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 ”

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operating conditions. B ased 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. T he 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, t hose 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 p lant s

. 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, t he goal for visibility in the Gorge is continued improvement over time

. That means t racking 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 it s 2014 and 2018 regional haze plan work.

_______________ d oc name: 26

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- 03052014 .doc x
, March 5 , 2014

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The draft permit for the Troutdale Energy Center was place d on public no tice from September 4 , 2013, through October 14 , 2013. DEQ held a public hearing on October 3 , 2013. A tota l of 181 individuals and organizations submitted comments during the comment period.

Public involvement is an important part of the permit issuance process, and DEQ thank s everyone who commented for their involvement in the process and for their time and effort.

The comments are organ ized 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 Trout dal e 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 app licable 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 c ondition 1 in the draft permit.

Other minor typograp hical corrections were made when found. Such corrections did not change the requirements of the permit.

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# Contents

Comments by 177 individuals

................................ ................................ ................................ ................................ ....... 3

Comments by Darryl Usher

................................ ................................ ................................ ................................ ......... 11

Comments by Paul Wilcox

................................ ................................ ................................ ................................ .......... 11

Comments b y 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

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Comment s by 177 individuals

Commenters: Submitted by 177 c ommenters who are listed beginning on page 4

.

Summary of comment s : 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 ar eas

. The facility would harm businesses in the Gorge.

A dopt findings that the facility would cause signi ficant 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. T he 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

u ndermine 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 bu sinesses in the Gorge; or would cause signi ficant 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.

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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 S wanson 9606 26th Ave NW Seattle, WA 98117

- 2515

Dr. Barbara Manildi 3525 Red Cedar Way Lake Oswego, OR 97035

- 3523 (503) 635

- 4878

Mr. B enjamin I gnatowski

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 W agner 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

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4723 NE 14th Ave Portland, OR 97211

- 5011

Mr. Dave King

8728 N Edison St Portland, OR 97203

- 5316

Mr. Dav id 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 E vans 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

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Ms. Jan Polychronis

PO Box 639 The Dalles, OR 97058

- 0639

Ms. J ane Harold

1515 SW P endleton 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 S now 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 K irchhoff 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 K nipe 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

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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

- 640 9

Ms. Lydia Deems

241 Lakeside Dr White Salmon, WA 98672

- 9006 Ms. L ynda Cunningham

5505 E E vergreen 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

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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 Ci r 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, O R 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 C ohn

128 NE 43rd Ave Portland, OR 97213

- 1604

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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 G erould

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 L ange 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 Av e 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 G oeckermann Hugo R oad

Grants P ass, 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 G rimstad 41025 SE Washougal River Rd Washougal, WA 98671

- 5872

Ms. Kate Schmitt

PO Box 29083 Portland, OR 97296

- 9083

Ms. Kathryn Elich

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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

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Comment s 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 th e Gateway to the Columbia Gorge.

Response : Thank you for your comment.

Comment s by Paul Wilcox

Commenter:

Paul Wilcox

1030 SW 17 th 

### Way Troutdale, OR 97060

Summary of comments: The applicant has chosen the monetary path to offset CO 2 

### 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 vehi cle 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 th e CO 2 

### emissions offset program and the Public Utility Commission regulates utility costs. DEQ has no role in either the CO 2 

### emissions offset program or the regulation of utility costs.

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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 ensurin g that air quality in the entire state meets National Ambient Air Quality Standards. Air quality in the Portland Metro area currently meet s 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 ana lysis 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 relat ed to generating capacity

.

Comment s 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 a nd 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.

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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 betwe en 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 C enter. 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 installati on 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 kn ow 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 d ischarges. 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 neighborh ood?

Response: Comments 1 through 3 are outside the scope of the air quality permit ting program

.

Regarding c omment 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 loca tions 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

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Regarding comment 5, the daily amount of emissions from Troutdale Energy Center might be equivalent

to the amount of emissions from sever al hundred trucks, but the pollution effects of Troutdale Energy Center and several hundred trucks per day pass ing through the neighborhood would be quite different.

Emissions from trucks pa ssing through the neighborhood would occur in close proximity to r esidents

. 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 excee ded. For example, a 1

- hour ambient air quality standard for nitrogen dioxide (NO 2 

### ) was established in recent years by the U.S.

Environmen tal Protection A gency (EPA) and it is generally believed by both EPA and DEQ that the most likely location s for this st andard to be exceeded are near heavily travelled highways.

Regarding the effects of Troutdale Energy Center’s emission s
, DEQ required Troutdale Energy Center to perform a modeling analysis of the facility’s emissions. DEQ reviewed and approved t he analysis results and methodology

.

The analysis look ed 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 Lev els. The analysis indicates that e missions 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 excee dances of the 1

- hour NO 2 

### 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 NO 2 

### 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

p ermit and is available from DEQ.

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Comment s by NEDC, Friends of the Columbia Gorge and Columbia Riverkeeper

Commenters : Air Quality Group, Northwest Environmental Defense Cente r JJ England

Shanna Fricklas Matthew Ring Heather Fossity

Rachel Morris YoungWoo Joh

Erica Nist

- Lund

Friends of the Colum

bia 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 p eriods 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 requireme nt 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 yi elds

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 t o limit the hours of operation on ULSD as part of the BACT determination. DEQ did include lim its 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:

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(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 p rocesses 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 th at 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 ther eof, 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 turbin es for both fuel type s
, with the

except ion of G HGs 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 do es 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, a nd in consideration of comments received, reviewed condition

30

.

Condition 30 in the draft permit stated that t he combustion turbines must burn only natural gas except as

follows:

 The c ombined 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 pe r 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

Commiss ion (PUC), may curtai l 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 contac t ed Northwest Natural Gas to discuss curtailments and learned that the utility may curtail gas deliveries when local demand exceeds the

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utility’s ability to supply gas. This usually occurs during extreme cold weather and in a limited geographic area. Curta ilment 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

ar ea are contacted and told to curtail the use of gas. Cu rtailment is not effected by physically shutting off the flow of gas, but by the price pen alty in the interruptible rat e schedule. 1



### DEQ requested Troutdale Energy Center clarify their intentions with respect to the use of ULSD fuel. Troutdale Energy C enter provided the following information on December 23, 2013 :

“ Troutdale Energy Center, LLC (TEC) has requested the ability to use ULSD instead of na tural 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 pri ce 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 woul d 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.

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An Analysi s 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.

T he document i ncludes 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.” (pag e 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 .” (page s 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, a nd 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 ULS D in all turbines is consistent with limiting the use of ULSD to only those times when t he natural gas supply is “curtailed”, where DEQ now

under stands 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 doe s not have expertise in the area of natural gas pric ing and is unable to precisely define “extreme price volatility”

. However, DEQ notes that extreme price volatility might reasonably be indicated by

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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 n eeds to be specifically allowed.

DEQ has revise d condition 30 in the final permit to state that t he 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 e missions 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 calenda r 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 kee ping 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 a lso 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 port ion of this facility’s emissions will occur during startup/shutdown.

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Response: DEQ does not agree with commenters

.

The applicant submitted the following information in the permit application:

 the time periods required for startup s and shutdowns, and

 esti mates 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 emission s, 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 al so specif

ies the emissions and specifying the emissions also specifies the time. There fore, with regard to startups and shutdowns

, a time limit or an emissions limit are equiv alent 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 jurisdic tions 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 t ask and is intended to provide baseload or mid

peaking 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 app ly

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

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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 diffe rent 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 emi ssion 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 situat ion (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

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 su bstantially 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/s hutdown 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

- 00 14;

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

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feasible and appropriate based upon the Pio Pico Energy Center permitting decision, an d 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 informatio n from the appl icant a bout proposed turbine operating scenarios and turbine performanc e and emissi ons under a number of operating

load s.

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 hydro

generation output, the combined

- cycle power plant at the Troutdale Energy Center could also be

load followi ng. The combined

- cycle plant is therefore not comparable to base load resources in

ot her 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 pla nt 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 dimin ish. 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 outp ut 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, pag e 4

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DEQ concludes that all turbines at the proposed fa cility 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 tables 4 

### . 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/h r) 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.

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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 CO 2 

### 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(ton s) ] 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/MW h 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) 2 1,136 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) 2 844 878 884 923 1,311 1,406

Percent increase in CO2

emissions in lb/MWh over full load

-- -- 5% 9%

-- 7%

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T ables 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 load s . However, and perhaps counter

- intuitively, GHG emissions in pounds per megawatt

hour are at their minimum at full load and are higher at low load s

. DEQ understands that all combustion turbines exhibit the same basic performance characteristics; that is, they operate at maximum efficiency at

full load and at lowe r 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 re cognizes 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 BA CT 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 va rying 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.

T he fact that wind power is available at times means that , generally, less fuel overall must be burned to generate ele ctricity

. So, w hile an individual generating facility may have to operate in a less efficient manner, the electrical generating system as a wh ole 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 Center 5 

### , Pio Pico Energy Center 6 

### and Puget Sound Energy Fredonia Generating Station Expansion Project 7 

### . 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

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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

combu stion 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) 1,13 6 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 B ACT 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 re lation 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 combustio n turbines at low loads much of the time. DEQ believe s that setting G HG

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.

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The applicant has presented potential o perating scenarios in Tables 1 and 2 (on page 23 ) wh ich might reasonably occur in practice and which DEQ believes represent reasonable worst

- case scenario s. T he GHG BACT limits proposed in the draft permit are based on these scenarios and prop erly take into account the higher GHG emission rates (on a lb/MWh basis) at lower loa ds

.

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 ope ration, DEQ notes that t he proposed GHG BACT limits differ significantly from other proposed BACT limits in the draft permit in that the GHG BACT limits are lo ng

- term limits (annual average) as opposed to short

- term limits (averaged over hours). DEQ also notes that t he proposed GHG

BACT limits are based on a reaso nable 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. R ecalculating 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 sepa rate 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 prud ent 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 h as 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

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basis. Id. at 81

- 87. NEDC recognizes that this scenario is unlikely because t hese 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:

Conditi ons 47 and 49 are monitoring requirements for CO 2 

### 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 CO 2 

### 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 S ubpart 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

v ersion of whichever rule EPA revises

.

Comment : IV. Conditions 50 and 51 w ill 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 intende d 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

Sour ce 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/ca a/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 sp irit 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 prox y 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 T EC 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 equipm ent; 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

d etermining 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 V OC 9 

### and 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 r evised condition 5 0 to require additional testing while using ULSD as follows: Following the initial test, s ubsequent 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 r ecent 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 neede d.

U pon reconsideration of the proposed testing schedule, DEQ has revised condition 51 to require

ad ditional testing while using ULSD as follows: Following the initial test, s ubsequent 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.

Co mment: 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 visibili ty 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 l ight 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 problem atic 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

im provements 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 w hat 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 th e following:

“While not “zero”, the low and localized levels of TEC’s visibility a n d 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 supportin g 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 t he commenters’ comments, and DEQ does not agree with commenters that “ Previously mentioned issues in this permit, unless resolved,

10 Review of the U SFS 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. ”

Comment s 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 non

profit organization with approximately 5,000 members dedicated to protecting and enhancing the

resources of the Columbia River G orge. 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 th e 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 Qua lity 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 t hat 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 S ervice 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 prov ide 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 Cle an 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 implementa tion 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 Ar ea (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 inclu ded 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 scen ic 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 c ause 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 o rder 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 incorp orates 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 an d 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 permitti ng 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 Are a 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 ap pear 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” descr ibes 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 incorpo rates 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 Fo rest 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 responsibl e 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 resour ces 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 impa cts 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 S ervice 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 de tailed 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.

T he 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 Nati onal 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

t o 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 pro ject 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 Quali ty 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 modeli ng, 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 conti nued 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

- go ing 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 p lants 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 quali ty 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 o f 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 memoran dum to a cknowledge 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 again st 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 D EQ 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 comme nts 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 evaluatin g the significance of visibility and other air quality related values (AQRVs) in

f ederal Class I areas, which are pristine wilderness areas and national parks, have been long established by the Environmental Protection Agency and F ederal Land M anagers
, and are used in the PSD program

. Following DEQ guidance, t hese 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 conclud e d 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 G orge, 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 we ight 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 q uality impacts on the Gorge

, the USFS relie d heavily o n 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. T he Columbia River Gorge National Scenic Area is

not a Class I area , but a mix ed use area with both scenic and urban characteristics

. As noted above, DEQ

consider s 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 effective ness of Best Available Control Technology required by DEQ rule s . There is however no basis for requiring the us e of Class I thresholds

as a “ standard ” that must be met in the Gorge

. DEQ is also guided by the de finition of “adversely affect”

as used in the Gorge Scenic Area Act, which defines a n 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 show ed 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. B ased 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 undermin e 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. T he 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 emission s 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, t hose 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 f acilities such as the Boardman and Centralia coal

- fired power plant s

. As a

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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, t he goal for visibilit y 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 Colu mbia Gorge under it s 2014 and 2018 regional haze plan work.

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